UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2015
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From                 to                
Commission File Number: 001-33662
Forestar Group Inc.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
26-1336998
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)
6300 Bee Cave Road
Building Two, Suite 500
Austin, Texas 78746-5149
(Address of Principal Executive Offices, including Zip Code)
Registrant’s telephone number, including area code: (512) 433-5200
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange On Which Registered
Common Stock, par value $1.00 per share
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  ¨    No  þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.     Yes  ¨    No  þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  þ    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer þ
  
Non-accelerated filer o
 
Smaller reporting company o
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ¨    No  þ
The aggregate market value of the Common Stock held by non-affiliates of the registrant, based on the closing sales price of the Common Stock on the New York Stock Exchange on June 30, 2015, was approximately $275 million. For purposes of this computation, all officers, directors, and ten percent beneficial owners of the registrant (as indicated in Item 12) are deemed to be affiliates. Such determination should not be deemed an admission that such directors, officers, or ten percent beneficial owners are, in fact, affiliates of the registrant.
As of February 29, 2016, there were 33,906,986 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Selected portions of the Company’s definitive proxy statement for the 2016 annual meeting of stockholders are incorporated by reference into Part III of this Form 10-K.
 



TABLE OF CONTENTS
 
 
 
Page
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
 
Item 15.
 
 
 
 

2


PART I
 

Item 1.
Business
Overview
Forestar Group Inc. is a residential and mixed-use real estate development company. We own directly or through ventures interests in 58 residential and mixed-use projects comprised of 7,000 acres of real estate located in 11 states and 15 markets. We also own 590,000 net acres of oil and gas fee mineral interests located in Texas, Louisiana, Georgia and Alabama. In addition, we own interests in various other assets that have been identified as non-core that the company will exit opportunistically over time. Our non-core assets include our investment in oil and gas working interests, 89,000 acres of timberland and undeveloped land and commercial and income producing properties, which consists of one hotel, seven multifamily properties and two multifamily sites. In 2015, we had revenues of $262 million and net loss of $213 million. Unless the context otherwise requires, references to “we,” “us,” “our” and “Forestar” mean Forestar Group Inc. and its consolidated subsidiaries. Unless otherwise indicated, information is presented as of December 31, 2015, and references to acreage owned include approximate acres owned by us and ventures regardless of our ownership interest in a venture.
Key Initiatives
•
Reducing costs across our entire organization,
•
Reviewing entire portfolio of assets,
•
Reviewing capital structure; and
•
Providing additional information.
Business Segments
We manage our operations through three business segments:
•
Real estate,
•
Oil and gas, and
•
Other natural resources.
Our real estate segment provided approximately 77% percent of our 2015 consolidated revenues. We are focused on maximizing real estate value through the entitlement and development of strategically located residential and mixed-use communities. We secure entitlements by delivering thoughtful plans and balanced solutions that meet the needs of communities where we operate. Residential development activities target lot sales to local, regional and national homebuilders who build quality products and have strong and effective marketing and sales programs. The lots we develop in the majority of our communities are for mid-priced homes, predominantly in the first and second move up categories. We invest in projects principally in regions across the southern half of the United States that possess key demographic and growth characteristics that we believe make them attractive for long-term real estate investment. A majority of our active real estate projects are developed on land we or our ventures acquired in the open market. We also develop and own directly or through ventures, multifamily communities as income producing properties, principally in our target markets. On January 28, 2016, we announced that multifamily is a non-core business. As a result, we plan to opportunistically exit our multifamily portfolio and no longer allocate capital to new communities in this business.
Our oil and gas segment provided 20% percent of our 2015 consolidated revenues. We promote the exploration, development and production of oil and gas on our owned and leasehold mineral interests. These interests include 590,000 core owned mineral acres and 228,000 net mineral acres leased from others, which represent oil and gas working interests and have been identified as non-core.
Our other natural resources segment provided 3% percent of our 2015 consolidated revenues. We sell wood fiber from our land, primarily in Georgia, and lease land for recreational uses. We have 89,000 acres of non-core timberland and undeveloped land we own directly or through ventures. In addition, we have water interests in 1.5 million acres, including a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and 20,000 acres of groundwater leases in central Texas.
Our real estate origins date back to the 1955 incorporation of Lumbermen’s Investment Corporation, which in 2006 changed its name to Forestar (USA) Real Estate Group Inc. We have a decades long legacy of residential and commercial real estate development operations, primarily in Texas. Our oil and gas origins date back to the mid-1940s when we started leasing

3


our oil and gas mineral interests to third-party exploration and production companies. In 2007, Temple-Inland distributed all of the issued and outstanding shares of our common stock to its stockholders, which we will refer to as the “spin-off”.
Our results of operations, including information regarding our business segments, are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and in Item 8, Financial Statements and Supplementary Data.
2015 Significant Highlights (including ventures):
Real Estate
•
Sold 1,472 developed residential lots; average gross profit of approximately $34,400 per lot
•
Sold 13,862 acres of undeveloped land for almost $2,300 per acre
•
Sold 63 commercial acres for approximately $248,300 per acre
•
Sold 1,062 residential tract acres for almost $10,600 per acre
•
Sold Midtown Cedar Hill, a stabilized multifamily community, for $42.9 million, generating segment earnings of $9.3 million and reducing debt by $24.2 million

Oil and Gas
•
Incurred non-cash impairment charges of approximately $164.8 million related to unproved leasehold interests and proved properties principally due to the significant decline in oil prices and likelihood these non-core assets will be sold
•
Sold approximately 109,000 net leasehold mineral acres and 39 gross (7 net) producing wells for $17.8 million, primarily in Nebraska, Texas and North Dakota

Other Natural Resources
•
Sold nearly 227,000 tons of fiber for $13.50 per ton
Real Estate
In our real estate segment, we conduct project planning and management activities related to the acquisition, entitlement, development and sale of real estate, primarily residential and mixed-use communities, which we refer to as community development. We own and manage our projects either directly or through ventures, which we use to achieve a variety of business objectives, including more effective capital deployment, risk management, and leveraging a partner’s local market contacts and expertise. Our development projects are principally located in the major markets of Texas.
We have three real estate projects representing 4,400 acres currently in the entitlement process, which includes obtaining zoning and access to water, sewer and roads. Additional entitlements, such as flexible land use provisions, annexation, and the creation of local financing districts generate additional value for our business and may provide us the right to reimbursement of major infrastructure costs. We use return criteria, which include return on cost, internal rate of return, and cash multiples, when determining whether to invest initially or make additional investment in a project. When investment in development meets our return criteria, we will initiate the development process with subsequent sale of lots to home builders or for commercial tracts, internal development, sale to or venture with third parties.
We have 58 entitled, developed or under development projects in 11 states and 15 markets encompassing 7,000 acres planned for residential and commercial uses. We may sell land at any point when additional time required for entitlement or investment in development will not meet our return criteria. In 2015, we sold approximately 14,000 acres of undeveloped land at an average price of almost $2,300 per acre.
At year-end 2015, we have discontinued entitlement efforts on eight projects located in Georgia as we determined it is unlikely these will be developed and classified the acreage as higher and better use timberland. In addition, we have classified land associated with 12 projects as entitled undeveloped land as we determined it is unlikely these projects will be developed, resulting in a decrease of approximately 4,000 planned lots from our projects lot inventory.

4


A summary of our real estate projects in the entitlement process (a) at year-end 2015 follows:
Project
 
County
 
Market
 
Project Acres (b)
California
 
 
 
 
 
 
Hidden Creek Estates
 
Los Angeles
 
Los Angeles
 
700

Terrace at Hidden Hills
 
Los Angeles
 
Los Angeles
 
30

Texas
 
 
 
 
 
 
Lake Houston
 
Harris/Liberty
 
Houston
 
3,700

Total
 
 
 
 
 
4,430

 _____________________
(a) 
A project is deemed to be in the entitlement process when customary steps necessary for the preparation of an application for governmental land-use approvals, such as conducting pre-application meetings or similar discussions with governmental officials, have commenced, or an application has been filed. Projects listed may have significant steps remaining, and there is no assurance that entitlements ultimately will be received.
(b) 
Project acres, which are the total for the project regardless of our ownership interest, are approximate. The actual number of acres entitled may vary.

A summary of our non-core timberland and undeveloped land at year-end 2015 follows:
 
 
Acres
Timberland
 
 
Alabama
 
3,300

Georgia
 
45,900

Texas
 
14,300

Higher and Better Use Timberland (a)
 
 
Georgia
 
20,000

Entitled Undeveloped Land (b)
 
 
Georgia
 
5,100

Total
 
88,600

 _____________________
(a) 
Higher and better use timberland represents eight projects previously in the entitlement process. We have discontinued entitlement efforts as we determined it is unlikely these projects will be developed.
(b) 
Entitled undeveloped land represents 12 projects and nearly 4,000 planned future lots previously included with our projects in the development process. We determined it is unlikely these projects will be developed.
Products
The majority of our projects are single-family residential and mixed-use communities. In some cases, commercial land uses within a project enhance the desirability of the community by providing convenient locations for resident support services.
We develop lots for single-family homes and develop multifamily properties on our commercial tracts or other developed sites we may purchase. We sell residential lots primarily to local, regional and national home builders. We have 7,000 acres, principally in the major markets of Texas, comprised of land planned for about 13,900 residential lots. We generally focus our lot sales on the first and second move-up primary housing categories. First and second move-up segments are homes priced above entry-level products yet below the high-end and custom home segments. We also actively market and sell undeveloped land through our retail sales program.
Commercial tracts are developed internally or ventured with commercial developers that specialize in the construction and operation of income producing properties, such as apartments, retail centers, or office buildings. We also sell land designated for commercial use to regional and local commercial developers. We have about 1,100 acres of entitled land designated for commercial use.
Cibolo Canyons is a significant mixed-use project in the San Antonio market area. Cibolo Canyons includes 2,100 acres planned to include 1,769 residential lots, of which 997 have been sold as of year-end 2015 at an average price of $73,000 per lot. The residential component includes not only traditional single-family homes but also an active adult section, and is planned to include condominiums. The remaining 56 acres of commercial component is designated principally for multifamily and retail uses. Located at Cibolo Canyons is the JW Marriott® San Antonio Hill Country Resort & Spa (Resort), a 1,002 room

5


destination resort and two PGA Tour® Tournament Players Club® (TPC) golf courses designed by Pete Dye and Greg Norman. We have the right to receive from the Cibolo Canyons Special Improvement District (CCSID) nine percent of hotel occupancy revenues and 1.5 percent of other resort sales revenues collected as taxes by CCSID through 2034 and reimbursement of certain infrastructure costs related to the mixed-use development.
In 2014, we received $50,550,000 from CCSID principally related to its issuance of $48,900,000 Hotel Occupancy Tax (HOT) and Sales and Use Tax Revenue Bonds, resulting in recovery of our full Resort investment. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with the owner of the Resort to assign its senior rights to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable. The surety bond decreases as CCSID makes annual ad valorem tax rebate payments, which obligation is scheduled to be retired in full by 2020.

6


A summary of activity within our projects in the development process, which includes entitled, developed and under development single-family and mixed-use projects, at year-end 2015 follows:
 
 
 
 
 
 
Residential Lots/Units
 
Commercial Acres
Project
 
County
 
Interest
Owned (a)
 
Lots/Units Sold
Since
Inception
 
Lots/Units
Remaining
 
Acres Sold
Since
Inception
 
Acres
   Remaining
Projects with lots/units in inventory, under development or future planned development and projects with remaining commercial acres only
Texas
 
 
 
 
 
 
 
 
 
 
 
 
Austin
 
 
 
 
 
 
 
 
 
 
 
 
Arrowhead Ranch
 
Hays
 
100
%
 
—

 
381

 
—

 
11

The Colony
 
Bastrop
 
100
%
 
459

 
1,425

 
22

 
31

Double Horn Creek
 
Burnet
 
100
%
 
94

 
5

 
—

 
—

Entrada (b)
 
Travis
 
50
%
 
—

 
821

 
—

 
—

Hunter’s Crossing
 
Bastrop
 
100
%
 
510

 
—

 
54

 
49

La Conterra
 
Williamson
 
100
%
 
202

 
—

 
3

 
55

Westside at Buttercup Creek
 
Williamson
 
100
%
 
1,496

 
1

 
66

 
—

 
 
 
 
 
 
2,761

 
2,633

 
145

 
146

Corpus Christi
 
 
 
 
 
 
 
 
 
 
 
 
Caracol
 
Calhoun
 
75
%
 
12

 
62

 
—

 
14

Padre Island (b)
 
Nueces
 
50
%
 
—

 
—

 
—

 
15

Tortuga Dunes
 
Nueces
 
75
%
 
—

 
134

 
—

 
4

 
 
 
 
 
 
12

 
196

 
—

 
33

Dallas-Ft. Worth
 
 
 
 
 
 
 
 
 
 
 
 
Bar C Ranch
 
Tarrant
 
100
%
 
372

 
733

 
—

 
—

Keller
 
Tarrant
 
100
%
 
—

 
—

 
—

 
1

Lakes of Prosper
 
Collin
 
100
%
 
157

 
130

 
4

 
—

Lantana
 
Denton
 
100
%
 
1,249

 
515

 
14

 
—

Maxwell Creek
 
Collin
 
100
%
 
943

 
58

 
10

 
—

Parkside
 
Collin
 
100
%
 
19

 
181

 
—

 
—

The Preserve at Pecan Creek
 
Denton
 
100
%
 
598

 
184

 
—

 
7

River's Edge
 
Denton
 
100
%
 
—

 
202

 
—

 
—

Stoney Creek
 
Dallas
 
100
%
 
255

 
453

 
—

 
—

Summer Creek Ranch
 
Tarrant
 
100
%
 
983

 
268

 
35

 
44

Timber Creek
 
Collin
 
88
%
 
—

 
601

 
—

 
—

Village Park
 
Collin
 
100
%
 
567

 
—

 
3

 
2

 
 
 
 
 
 
5,143

 
3,325

 
66

 
54

Houston
 
 
 
 
 
 
 
 
 
 
 
 
Barrington Kingwood
 
Harris
 
100
%
 
176

 
4

 
—

 
—

City Park
 
Harris
 
75
%
 
1,311

 
157

 
52

 
113

Harper’s Preserve (b)
 
Montgomery
 
50
%
 
513

 
1,215

 
30

 
49

Imperial Forest
 
Harris
 
100
%
 
—

 
428

 
—

 
—

Long Meadow Farms (b)
 
Fort Bend
 
38
%
 
1,551

 
253

 
190

 
115

Southern Trails (b)
 
Brazoria
 
80
%
 
915

 
81

 
1

 
—

Spring Lakes
 
Harris
 
100
%
 
348

 
—

 
25

 
4

Summer Lakes
 
Fort Bend
 
100
%
 
722

 
347

 
56

 
—

Summer Park
 
Fort Bend
 
100
%
 
102

 
97

 
32

 
64

Willow Creek Farms II
 
Waller/Fort Bend
 
90
%
 
90

 
175

 
—

 
—

 
 
 
 
 
 
5,728

 
2,757

 
386

 
345

San Antonio
 
 
 
 
 
 
 
 
 
 
 
 
Cibolo Canyons
 
Bexar
 
100
%
 
997

 
772

 
130

 
56

Oak Creek Estates
 
Comal
 
100
%
 
273

 
281

 
13

 
—

Olympia Hills
 
Bexar
 
100
%
 
740

 
14

 
10

 
—

Stonewall Estates (b)
 
Bexar
 
50
%
 
371

 
19

 
—

 
—

 
 
 
 
 
 
2,381

 
1,086

 
153

 
56

Total Texas
 
 
 
 
 
16,025

 
9,997

 
750

 
634

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

7


 
 
 
 
 
 
Residential Lots/Units
 
Commercial Acres
Project
 
County
 
Interest
Owned (a)
 
Lots/Units Sold
Since
Inception
 
Lots/Units
Remaining
 
Acres Sold
Since
Inception
 
Acres
   Remaining
Colorado
 
 
 
 
 
 
 
 
 
 
 
 
Denver
 
 
 
 
 
 
 
 
 
 
 
 
Buffalo Highlands
 
Weld
 
100
%
 
—

 
164

 
—

 
—

Johnstown Farms
 
Weld
 
100
%
 
281

 
313

 
2

 
3

Pinery West
 
Douglas
 
100
%
 
86

 
—

 
20

 
106

Stonebraker
 
Weld
 
100
%
 
—

 
603

 
—

 
—

 
 
 
 
 
 
367

 
1,080

 
22

 
109

Georgia
 
 
 
 
 
 
 
 
 
 
 
 
Atlanta
 
 
 
 
 
 
 
 
 
 
 
 
Harris Place
 
Paulding
 
100
%
 
22

 
5

 
—

 
—

Montebello (b) (c)
 
Forsyth
 
90
%
 
—

 
220

 
—

 
—

Seven Hills
 
Paulding
 
100
%
 
851

 
231

 
26

 
113

West Oaks
 
Cobb
 
100
%
 
—

 
56

 
—

 
—

 
 
 
 
 
 
873

 
512

 
26

 
113

North & South Carolina
 
 
 
 
 
 
 
 
 
 
 
 
Charlotte
 
 
 
 
 
 
 
 
 
 
 
 
Ansley Park
 
Lancaster
 
100
%
 
—

 
304

 
—

 
—

Habersham
 
York
 
100
%
 
28

 
159

 
—

 
7

Walden
 
Mecklenburg
 
100
%
 
—

 
387

 
—

 
—

 
 
 
 
 
 
28

 
850

 
—

 
7

Raleigh
 
 
 
 
 
 
 
 
 
 
 
 
Beaver Creek (b)
 
Wake
 
90
%
 
—

 
193

 
—

 
—

 
 
 
 
 
 
—

 
193

 
—

 
—

 
 
 
 
 
 
28

 
1,043

 
—

 
7

Tennessee
 
 
 
 
 
 
 
 
 
 
 
 
Nashville
 
 
 
 
 
 
 
 
 
 
 
 
Beckwith Crossing
 
Wilson
 
100
%
 
—

 
99

 
—

 
—

Morgan Farms
 
Williamson
 
100
%
 
104

 
69

 
—

 
—

Vickery Park
 
Williamson
 
100
%
 
—

 
87

 
—

 
—

Weatherford Estates
 
Williamson
 
100
%
 
—

 
17

 
—

 
—

 
 
 
 
 
 
104

 
272

 
—

 
—

Wisconsin
 
 
 
 
 
 
 
 
 
 
 
 
Madison
 
 
 
 
 
 
 
 
 
 
 
 
Juniper Ridge/Hawks Woods (b) (c)
 
Dane
 
90
%
 
—

 
215

 
—

 
—

Meadow Crossing II (b) (c)
 
Dane
 
90
%
 
—

 
172

 
—

 
—

 
 
 
 
 
 
—

 
387

 
—

 
—

Arizona, California, Missouri, Utah
 
 
 
 
 
 
 
 
 
 
 
 
Tucson
 
 
 
 
 
 
 
 
 
 
 
 
Boulder Pass (b) (c)
 
Pima
 
50
%
 
—

 
88

 
—

 
—

Dove Mountain
 
Pima
 
100
%
 
—

 
98

 
—

 
—

Oakland
 
 
 
 
 
 
 
 
 
 
 
 
San Joaquin River
 
Contra Costa/Sacramento
 
100
%
 
—

 
—

 
—

 
288

Kansas City
 
 
 
 
 
 
 
 
 
 
 
 
Somerbrook
 
Clay
 
100
%
 
173

 
222

 
—

 
—

Salt Lake City
 
 
 
 
 
 
 
 
 
 
 
 
Suncrest (b) (d)
 
Salt Lake
 
90
%
 
—

 
181

 
—

 
—

 
 
 
 
 
 
173

 
589

 
—

 
288

Total
 
 
 
 
 
17,570

 
13,880

 
798

 
1,151

___________________
(a) 
Interest owned reflects our net equity interest in the project, whether owned directly or indirectly. There are some projects that have multiple ownership structures within them. Accordingly, portions of these projects may appear as owned, consolidated or accounted for using the equity method.
(b) 
Projects in ventures that we account for using equity method.

8


(c)
Venture project that develops and sells homes.
(d)
Venture project that develops and sells lots and homes.
A summary of our significant non-core commercial and income producing properties at year-end 2015 follows:
Project
 
Market
 
Interest
Owned (a)
 
Type
 
Acres
 
Description
Radisson Hotel & Suites (b)
 
Austin
 
100
%
 
Hotel
 
2

 
413 guest rooms and suites
Dillon (c)
 
Charlotte
 
100
%
 
Multifamily
 
3

 
379-unit luxury apartment
Eleven
 
Austin
 
100
%
 
Multifamily
 
3

 
257-unit luxury apartment
Music Row (c)
 
Nashville
 
100
%
 
Multifamily
 
1

 
230-unit luxury apartment
Elan 99 (c)
 
Houston
 
90
%
 
Multifamily
 
17

 
360-unit luxury apartment
Acklen (c)
 
Nashville
 
30
%
 
Multifamily
 
4

 
320-unit luxury apartment
HiLine (c)
 
Denver
 
25
%
 
Multifamily
 
18

 
385-unit luxury apartment
360° (c)
 
Denver
 
20
%
 
Multifamily
 
4

 
304-unit luxury apartment
_____________________
(a) 
Interest owned reflects our net equity interest in the project, whether owned directly or indirectly.
(b) 
Under contract to be sold for $130.0 million and the transaction is expected to close in second quarter 2016.
(c) 
Construction in progress.
Our net investment in owned and consolidated real estate projects by geographic location at year-end 2015 follows:
State
 
Entitled,
Developed,
and Under
Development
Projects
 
Undeveloped
Land and
Land in
Entitlement
 
Income
Producing
Properties
 
Total
 
 
(In thousands)
Texas
 
$
263,202

 
$
5,809

 
$
106,459

 
$
375,470

Georgia
 
5,244

 
67,149

 
—

 
72,393

North Carolina
 
25,282

 
118

 
19,987

 
45,387

California
 
8,915

 
24,589

 
—

 
33,504

Tennessee
 
16,862

 
10

 
9,947

 
26,819

Colorado
 
23,917

 
245

 
—

 
24,162

Other
 
8,719

 
261

 
—

 
8,980

Total
 
$
352,141

 
$
98,181

 
$
136,393

 
$
586,715

Approximately 64 percent of our net investment in real estate is in the major markets of Texas.
Markets
Sales of new U.S. single-family homes rose to a seven-year high in December 2015, on a seasonally adjusted basis, but remain well below historical levels. Inventories of new homes are near historically low levels in many areas. In addition, declining finished lot inventories and limited supply of economically developable raw land has increased demand for our developed lots. However, national and global economic weakness and uncertainty, and a restrictive mortgage lending environment continue to threaten a robust recovery in the housing market, despite low interest rates. Multifamily market conditions continue to be strong, with many markets experiencing healthy occupancy levels and positive rent growth. This improvement has been driven primarily by limited housing inventory, reduced single-family mortgage credit availability, and the increased propensity to rent among the 18 to 34 year old demographic of the U.S. population.
 Competition
We face significant competition for the acquisition, entitlement, development and sale of real estate in our markets. Our major competitors include other landowners who market and sell undeveloped land and numerous national, regional and local developers. In addition, our projects compete with other development projects offering similar amenities, products and/or locations. Competition also exists for investment opportunities, financing, available land, raw materials and labor, with entities that may possess greater financial, marketing and other resources than us. The presence of competition may increase the bargaining power of property owners seeking to sell. These competitive market pressures sometimes make it difficult to acquire, entitle, develop or sell land at prices that meet our return criteria. Some of our real estate competitors are well established and financially strong, may have greater financial resources than we do, or may be larger than us and/or have lower cost of capital and operating costs than we have and expect to have.

9


The land acquisition and development business is highly fragmented, and we are unaware of any meaningful concentration of market share by any one competitor. Enterprises of varying sizes, from individuals or small companies to large corporations, actively engage in the real estate development business. Many competitors are local, privately-owned companies. We have a few regional competitors and virtually no national competitors other than national home builders that, depending on business cycles and market conditions, may enter or exit the real estate development business in some locations to develop lots on which they construct and sell homes. During periods when access to capital is restricted, participants with weaker financial conditions tend to be less active.
Oil and Gas
Our oil and gas segment is focused on maximizing the value from our owned oil and gas mineral interests through promoting exploration, development and production activities by increasing acreage leased, lease rates, and royalty interests.
We typically lease our owned mineral interests to third parties for exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and retain a royalty interest.
In addition, we are focused on exiting our non-core working interest oil and gas assets, principally in the Bakken/Three Forks of North Dakota and Lansing Kansas City formation of Nebraska and Kansas. We only intend to allocate capital going forward to these non-core assets to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.
Owned Mineral Interests
We own mineral interests beneath 590,000 net acres located in the United States, principally in Texas, Louisiana, Georgia and Alabama. Our revenue from our owned mineral interests is primarily from oil and gas royalty interests, lease bonus payments and delay rentals received and other related activities. We engage in leasing certain portions of these mineral interests to third parties for the exploration and production of oil and gas.
At year-end 2015, of our 590,000 net acres of owned mineral interests, 535,000 net acres are available for lease. We have about 55,000 net acres leased for oil and gas exploration activities, of which about 42,000 net acres are held by production from over 534 gross oil and gas wells that are operated by others, in which we have royalty interest. In addition, we have working interest ownership in 31 of these wells.
A summary of our owned mineral acres (a) at year-end 2015 follows:
State
 
Unleased
 
Leased (b)
 
Held By
Production (c)
 
Total (d)
Texas
 
211,000

 
9,000

 
32,000

 
252,000

Louisiana
 
130,000

 
4,000

 
10,000

 
144,000

Georgia
 
152,000

 
—

 
—

 
152,000

Alabama
 
40,000

 
—

 
—

 
40,000

California
 
1,000

 
—

 
—

 
1,000

Indiana
 
1,000

 
—

 
—

 
1,000

 
 
535,000

 
13,000

 
42,000

 
590,000

 _____________________
(a)
Includes ventures.
(b)
Includes leases in primary lease term or for which a delayed rental payment has been received. In the ordinary course of business, leases covering a significant portion of leased net mineral acres may expire from time to time in a single reporting period.
(c)
Acres being held by production are producing oil or gas in paying quantities.
(d)
Texas, Louisiana, California and Indiana net acres are calculated as the gross number of surface acres multiplied by our percentage ownership of the mineral interest. Alabama and Georgia net acres are calculated as the gross number of surface acres multiplied by our estimated percentage ownership of the mineral interest based on county sampling.

10


A summary of our Texas and Louisiana owned mineral acres (a) primarily in East Texas and Gulf Coast Basins by county or parish at year-end 2015 follows:
Texas
 
Louisiana (b)
County
 
Net Acres
 
Parish
 
Net Acres
Trinity
 
46,000

 
Beauregard
 
79,000

Angelina
 
42,000

 
Vernon
 
39,000

Houston
 
29,000

 
Calcasieu
 
17,000

Anderson
 
25,000

 
Allen
 
7,000

Cherokee
 
24,000

 
Rapides
 
1,000

Sabine
 
23,000

 
Other
 
1,000

Red River
 
14,000

 
 
 
144,000

Newton
 
13,000

 
 
 
 
San Augustine
 
13,000

 
 
 
 
Jasper
 
12,000

 
 
 
 
Other
 
11,000

 
 
 
 
 
 
252,000

 
 
 
 
 _____________________
(a)
Includes ventures. These owned mineral acre interests contain numerous oil and gas producing formations consisting of conventional, unconventional, and tight sand reservoirs. Of these reservoirs, we have mineral interests in and around production trends in the Wilcox, Frio, Cockfield, James Lime, Pettet, Travis Peak, Cotton Valley, Austin Chalk, Haynesville Shale, Barnett Shale and Bossier formations.
(b)
A significant portion of our Louisiana net mineral acres were severed from the surface estate shortly before our 2007 spin-off. Under Louisiana law, a mineral servitude that is not producing minerals or which has not been the subject of good-faith drilling operations will cease to burden the property upon the tenth anniversary of the date of its creation. Approximately 40,000 acres of our Louisiana owned net mineral acres may revert to the surface owner in 2017 unless drilling operations are commenced prior to the tenth anniversary of severance from the surface.
We engage in leasing certain portions of our owned mineral interests to third parties for the exploration and production of oil and gas. Leasing mineral acres for exploration and production can create significant value because we may negotiate a lease bonus payment and retain a royalty interest in all revenues generated by the lessee from oil and gas production. The significant terms of these arrangements include granting the exploration company the rights to oil or gas it may find and requiring that drilling be commenced within a specified period. In return, we may receive an initial lease payment (bonus), subsequent payments if drilling has not started within the specified period (delay rentals), and a percentage interest in the value of any oil or gas produced (royalties). If no oil or gas is produced during the required period, all rights are returned to us. Historically, our capital requirements for our owned mineral acres have been minimal.
Our royalty revenues are contractually defined and based on a percentage of production and are received in cash. Our royalty revenues fluctuate based on changes in the market prices for oil and gas, the decline in production in existing wells, and other factors affecting the third-party oil and gas exploration and production companies that operate wells on our minerals including the cost of development and production.
Most leases are for a three to five year term although a portion or all of a lease may be extended by the lessee as long as actual production is occurring. Financial terms vary based on a number of market factors including the location of the mineral interest, the number of acres subject to the agreement, proximity to transportation facilities such as pipelines, depth of formations to be drilled and risk.
Mineral Interests Leased
As of year-end 2015, our leasehold interests include 228,000 net mineral acres leased from others, principally located in Nebraska and Kansas primarily targeting the Lansing – Kansas City formation and in North Dakota primarily targeting the Bakken and Three Forks formations. We have 43,000 net acres held by production and 369 gross oil and gas wells with working interest ownership, of which 126 are operated by us. These assets have been identified as non-core and we plan to exit these assets over time and we only intend to allocate capital going forward only to preserve value and optionality of the ultimate sale as we evaluate exiting these assets.

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A summary of our net mineral acres leased from others as of year-end 2015 follows:
State
 
Undeveloped (b)
 
Held By
Production
 
Total
Nebraska
 
136,000

 
10,000

 
146,000

Kansas
 
9,000

 
8,000

 
17,000

Oklahoma
 
14,000

 
17,000

 
31,000

North Dakota
 
4,000

 
5,000

 
9,000

Other (a) 
 
22,000

 
3,000

 
25,000

 
 
185,000

 
43,000

 
228,000

 __________________
(a)
Excludes 8,000 net acres of overriding royalty interests
(b) 
We have 82,000 gross and 57,000 net undeveloped acres scheduled to expire in 2016.
Nebraska and Kansas
We have 163,000 net mineral acres primarily located on or near the Central Kansas Uplift formations located in the western Kansas counties of Graham, Lane, Thomas and Rawlins and in the southwest portion of Nebraska in the counties of Dundy, Red Willow and Hitchcock. At year-end 2015, we own working interests in 135 gross producing wells with an average working interest of 51 percent. These assets were sold for $21.0 million in first quarter 2016.
Oklahoma
We have 31,000 net mineral acres located in the Anadarko Basin. At year-end 2015, we own working interests in 76 gross producing wells with an average working interest of 39 percent. In first quarter 2016, we sold 16,700 net acres and 40 gross (8 net) wells in Oklahoma for $2.1 million.
North Dakota
We have 9,000 net acres in or near the core of the Bakken and Three Forks formations. Most of the acreage is located on the Fort Berthold Indian Reservation, south and west of the Parshall Field. We own working interests in 137 gross producing oil wells with an average working interest of 8 percent. Where a well has been drilled on a spacing unit, in many cases we expect additional development wells to be drilled on those spacing units in the future.
Most leases are for a three to five year term although a portion or all of a lease may be extended as long as production is occurring. Financial terms vary based on a number of factors including the location of the leasehold interest, the number of acres subject to the agreement, proximity to transportation facilities such as pipelines, depth of formations to be drilled and risk.
Estimated Proved Reserves    
Our net estimated proved oil and gas reserves, all of which are located in the United States, as of year-end 2015, 2014 and 2013 are set forth in the table below. We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc.(NSAI), to assist us in preparing estimates of our proved oil and gas reserves in accordance with the definitions and guidelines of the Securities and Exchange Commission (SEC).

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Net quantities of proved oil and gas reserves related to our working and royalty interests follow:
 
Reserves
 
Oil (a)
(Barrels)
 
Gas
(Mcf)
 
(In thousands)
Consolidated entities:
 
 
 
Proved developed
5,179

 
7,957

Proved undeveloped
—

 
—

Total proved reserves 2015
5,179

 
7,957

Proved developed
5,269

 
10,848

Proved undeveloped
2,403

 
1,801

Total proved reserves 2014
7,672

 
12,649

Proved developed
3,893

 
11,385

Proved undeveloped
1,931

 
2,245

Total proved reserves 2013
5,824

 
13,630

Our share of ventures accounted for using the equity method:
 
 
 
Proved developed
—

 
1,263

Proved undeveloped
—

 
—

Total proved reserves 2015
—

 
1,263

Proved developed
—

 
1,751

Proved undeveloped
—

 
—

Total proved reserves 2014
—

 
1,751

Proved developed
—

 
2,332

Proved undeveloped
—

 
—

Total proved reserves 2013
—

 
2,332

Total consolidated and our share of equity method ventures:
 
 
 
Proved developed
5,179

 
9,220

Proved undeveloped
—

 
—

Total proved reserves 2015
5,179

 
9,220

Proved developed
5,269

 
12,599

Proved undeveloped
2,403

 
1,801

Total proved reserves 2014
7,672

 
14,400

Proved developed
3,893

 
13,717

Proved undeveloped
1,931

 
2,245

Total proved reserves 2013
5,824

 
15,962

 _____________________
(a) 
Includes natural gas liquids.

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The following summarizes the changes in proved reserves for 2015:
 
Reserves
 
Oil
(Barrels)
 
Gas
(Mcf)
 
(In thousands)
Consolidated entities:
 
 
 
Year-end 2014
7,672

 
12,649

Revisions of previous estimates
(855
)
 
(1,675
)
Extensions and discoveries
224

 
173

Acquisitions
—

 
—

Sales
(704
)
 
(1,223
)
Production
(1,158
)
 
(1,967
)
Year-end 2015
5,179

 
7,957

Our share of ventures accounted for using the equity method:
 
 
 
Year-end 2014
—

 
1,751

Revisions of previous estimates
—

 
(320
)
Extensions and discoveries
—

 
—

Production
—

 
(168
)
Year-end 2015
—

 
1,263

Total consolidated and our share of equity method ventures:
 
 
 
Year-end 2015
5,179

 
9,220

We do not have any estimated reserves of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas.
At year-end 2015, we have no barrels of oil equivalent (BOE) of proved undeveloped (PUD) reserves based on our plan to exit non-core oil and gas working interest assets and only allocate capital to preserve value and optionality for the ultimate sale as we evaluate exiting these assets. At year-end 2014, we had 2,703,000 BOE of PUD reserves. The decline in PUD reserves is principally due to (i) downward revisions of 1,694,000 BOE related to the continued decline in oil and gas prices during 2015, (ii) the conversion of 610,000 BOE of PUD reserves to proved developed reserves, and (iii) various asset divestments which included 399,000 BOE of PUD reserves. As a percent of our total proved reserves, PUD reserves were 0% at year-end 2015 and 27% at year-end 2014.
In 2015, we invested approximately $9,205,000 to convert 610,000 BOE of PUD reserves into proved developed reserves.
Reserve estimates were based on the economic and operating conditions existing at year-end 2015, 2014 and 2013. Oil and gas prices are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December. For 2015, 2014 and 2013, prices used for reserve estimates were $50.28, $94.99 and $96.91 per barrel of West Texas Intermediate Crude Oil and gas prices of $2.59, $4.35 and $3.67 per MMBTU per the Henry Hub spot market. All prices were then adjusted for quality, transportation fees and regional price differentials. Since the determination and valuation of proved reserves is a function of the interpretation of engineering and geologic data and prices for oil and gas and the cost to produce these reserves, the reserves presented should be expected to change as future information becomes available. For an estimate of the standardized measure of discounted future net cash flows from proved oil and gas reserves, please read Note 19  — Supplemental Oil and Gas Disclosures (Unaudited) to our consolidated financial statements included Part II, Item 8 of this Annual Report on Form 10-K.
The process of estimating oil and gas reserves is complex, involving decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, capital costs, operating costs, revenues, taxes and quantities of recoverable oil and gas reserves might vary from those estimated. Any variance could materially affect the estimated quantities and present value of proved reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, development, prevailing oil and gas prices and other factors, many of which are beyond our control.
The primary internal technical person in charge of overseeing our reserves estimates has a Bachelor of Science in Physics and Mathematics and a Masters of Science in Civil Engineering. He has over 40 years of domestic and international experience in the exploration and production business including 40 years of reserve evaluations. He has been a registered Professional Engineer for over 25 years.
As part of our internal control over financial reporting, we have a process for reviewing well production data and division of interest percentages prior to submitting well level data to NSAI to assist us in preparing reserve estimates. Our primary

14


internal technical person and other members of management review the reserve estimates prepared by NSAI, including the underlying assumptions and estimates upon which they are based, for accuracy and reasonableness.
Production
In 2015, 2014 and 2013, oil and gas produced was approximately 1,158,500, 931,100 and 697,700 barrels of oil at an average realized price of $40.08, $80.63 and $89.40 per barrel and 2,134.8, 2,060.2 and 2,158.5 MMcf of gas at an average realized price of $2.60, $4.19 and $3.46 per Mcf. Natural gas liquids (NGLs) are aggregated with oil volumes and prices.
In 2015, 2014 and 2013, production lifting costs, which exclude ad valorem and severance taxes, were $12.95, $13.40 and $10.35 per BOE related to 369, 393 and 497 gross wells.
Drilling and Other Exploratory and Development Activities
The following tables set forth the number of gross and net oil and gas wells in which we participated:
Gross Wells
 
 
 
 
Exploratory
 
Development
Year
 
Total
 
Oil
 
Gas
 
Dry
 
Oil
 
Gas
 
Dry
2015 (a)
 
38

 
2

 
—

 
1

 
34

 
—

 
1

2014 (b)
 
119

 
21

 
—

 
32

 
46

 
1

 
19

2013
 
120

 
10

 
—

 
30

 
71

 
—

 
9

 _____________________
(a) 
Of the gross wells drilled in 2015, we operated 3 wells or 8 percent. The remaining wells represent our participations in wells operated by others. The exploratory dry hole was located in Oklahoma.
(b) 
Of the gross wells drilled in 2014, we operated 72 wells or 61 percent. The remaining wells represent our participations in wells operated by others. Dry holes were principally located in Nebraska, Kansas and Oklahoma.
Net Wells
 
 
 
 
Exploratory
 
Development
Year
 
Total
 
Oil
 
Gas
 
Dry
 
Oil
 
Gas
 
Dry
2015
 
6.3

 
0.7

 
—

 
0.8

 
4.3

 
—

 
0.5

2014
 
57.3

 
11.9

 
—

 
20.1

 
13.6

 
0.1

 
11.6

2013
 
46.7

 
6.0

 
—

 
18.2

 
16.8

 
—

 
5.7

Present Activities
At year-end 2015, there were 7 gross wells (1.2 net) being drilled in North Dakota and there were 2 gross wells (0.1 net) in North Dakota in some stage of the completion process requiring additional activities prior to generating sales.
Delivery Commitments
We have no oil or gas delivery commitments.

15


Wells and Acreage
The number of productive wells as of year-end 2015 follows:
 
Productive Wells (a)
 
Gross
 
Net
Consolidated entities:

 
 
Oil
577

 
114.8

Gas
303

 
48.6

Total
880

 
163.4

Ventures accounted for using the equity method:
 
 
 
Oil
—

 
—

Gas
23

 
1.8

Total
23

 
1.8

Total consolidated and equity method ventures:
 
 
 
Oil
577

 
114.8

Gas
326

 
50.4

Total
903

 
165.2

 _____________________
(a) 
Excludes 1,200 overriding royalty interest wells.
At year-end 2015, 2014 and 2013, we have royalty interests in 534, 551 and 547 gross wells. In addition, at year-end 2015, 2014 and 2013, we have working interests in 400, 426 and 497 gross wells. Our plugging liabilities are accrued on the balance sheet based on the present value of our estimated future obligation.
We did not have any wells with production of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas as of year-end 2015, 2014 or 2013.
At year-end 2015, our working interests represent approximately 114,000 gross developed acres and 43,000 net developed acres leased from others that are held by production. We had approximately 249,000 gross undeveloped acres and 185,000 net undeveloped acres at year-end 2015.
Markets
Oil and gas revenues are influenced by prices of, and global and domestic supply and demand for, oil and gas. These commodities as determined by both regional and global markets depend on numerous factors beyond our control, including seasonality, the condition of the domestic and global economies, political conditions in other oil and gas producing countries, the extent of domestic production and imports of oil and gas, the proximity and capacity of gas pipelines and other transportation facilities, supply and demand for oil and gas and the effects of federal, state and local regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. Global supply and demand fundamentals for crude oil at year-end 2015 remained out of balance with high global inventories and slower global growth. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48% lower than in 2014, and ended 2015 at $37.13 per Bbl. OPEC continues to produce at record high levels, focused on maintaining market share, and the lifting of sanctions against Iran introduces additional supply into the global market. Estimates for global demand growth continue to be tempered and could extend the global supply glut, resulting in an extended period of low crude oil pricing.
Mineral leasing activity is influenced by changes in commodity prices, the location of our owned mineral interests relative to existing or projected oil and gas reserves, the proximity of successful production efforts to our mineral interests and the evolution of new plays and improvements in drilling and extraction technology.
Competition
The oil and gas industry is highly competitive, and we compete with a substantial number of other companies that may have greater resources than us. Many of these companies explore for, produce and market oil and gas, carry on refining operations and market the end products on a worldwide basis. The primary areas in which we face competition are from alternative fuel sources, including coal, heating oil, imported LNG, nuclear and other nonrenewable fuel sources, and renewable fuel sources such as wind, solar, geothermal, hydropower and biomass. Competitive conditions may also be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government. It is not possible to predict whether such legislation or regulation may ultimately be adopted or its precise effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and gas.

16


In locations where our owned mineral interests are close to producing wells and proven reserves, we may have multiple parties interested in leasing our minerals. Conversely, where our mineral interests are in or near areas where reserves have not been discovered, we may receive nominal interest in leasing our minerals. Portions of our Texas and Louisiana minerals are in close proximity to producing wells and proven reserves. Interest in leasing our minerals is correlated with the economics of production which are substantially influenced by current oil and gas prices and improvements in drilling and extraction technologies.
Other Natural Resources
We sell wood fiber from portions of our land, primarily in Georgia, and lease land for recreational uses. We have 89,000 acres of non-core timberland and undeveloped land we own directly or through ventures. At year-end 2015, approximately 99 percent of available acres of our land including ventures, primarily in Georgia, are leased for recreational purposes. Most recreational leases are for a one-year term but may be terminated by us on 30 days’ notice to the lessee. These leases do not inhibit our ability to harvest timber. We have water interests in 1.5 million acres which includes a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and 20,000 acres of groundwater leases in central Texas. We have not received significant revenues or earnings from these interests.
Competition
We face significant competition from other landowners for the sale of wood fiber. Some of these competitors own similar timber assets that are located in the same or nearby markets. However, due to its weight, the cost for transporting wood fiber long distances is significant, resulting in a competitive advantage for timber that is located reasonably close to paper and building products manufacturing facilities. A significant portion of our wood fiber is reasonably close to such facilities so we expect continued demand for our wood fiber.
Employees
At year-end 2015, we had 106 employees. None of our employees participate in collective bargaining arrangements. We believe we have a good relationship with our employees.
Environmental Regulations
Our operations are subject to federal, state and local laws, regulations and ordinances relating to protection of public health and the environment. Changes to laws and regulations may adversely affect our ability to develop real estate, produce oil and gas, harvest and sell timber, or withdraw groundwater, or may require us to investigate and remediate contaminated properties.These laws and regulations may relate to, among other things, water quality, endangered species, protection and restoration of natural resources, timber harvesting practices, production of hydrocarbons and remedial standards for contaminated property and groundwater. Additionally, these laws may impose liability on property owners or operators for the costs of removal or remediation of hazardous or toxic substances on real property, without regard to whether the owner or operator knew, or was responsible for, the presence of the hazardous or toxic substances. The presence of, or the failure to properly remediate, such substances may adversely affect the value of a property, as well as our ability to sell the property or to borrow funds using that property as collateral or the ability to produce oil and gas from that property. Environmental claims generally would not be covered by our insurance programs.
The particular environmental laws that apply to any given site vary according to the site’s location, its environmental condition, and the present and former uses of the site and adjoining properties. Environmental laws and conditions may result in delays, may cause us to incur substantial compliance or other costs and can prohibit or severely restrict development activity or mineral production in environmentally sensitive regions or areas, which could negatively affect our results of operations.
At year-end 2015, we owned 288 acres in several parcels in or near Antioch, California, portions of which were sites of a paper manufacturing operation that are in remediation. The remediation is being conducted voluntarily with oversight by the California Department of Toxic Substances Control, or DTSC. We have received certificates of completion on all but one 80 acre tract, a portion of which includes subsurface contamination. We increased our reserves for environmental remediation by $689,000 from 2014 to 2015 due to additional testing and remediation requirements by state regulatory agencies. At year-end 2015, our accrued liability to complete remediation activities is $682,000, which is included in other accrued expenses.
Oil and gas operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, processing, storage, transportation, disposal and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations affect our operations and costs as a result of their impact on oil and gas production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional

17


pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.
Compliance with environmental laws and regulations increases our overall cost of business, but has not had, to date, a material adverse effect on our operations, financial condition or results of operations. It is not anticipated, based on current laws and regulations, that we will be required in the near future to expend amounts (whether for environmental control equipment, modification of facilities or otherwise) that are material in relation to our total development expenditure program in order to comply with such laws and regulations. However, given that such laws and regulations are subject to change, we are unable to predict the ultimate cost of compliance or the ultimate effect on our operations, financial condition and results of operations.
Available Information
Forestar Group Inc. is a Delaware corporation. Our principal executive offices are located at 6300 Bee Cave Road, Building Two, Suite 500, Austin, Texas 78746-5149. Our telephone number is (512) 433-5200.
From our Internet website, http://www.forestargroup.com, you may obtain additional information about us including:
•
our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents as soon as reasonably practicable after we file them with the Securities and Exchange Commission;
•
beneficial ownership reports filed by officers, directors, and principal security holders under Section 16(a) of the Securities Exchange Act of 1934, as amended (or the “Exchange Act”); and
•
corporate governance information that includes our:
•
corporate governance guidelines,
•
audit committee charter
•
management development and executive compensation committee charter,
•
nominating and governance committee charter,
•
standards of business conduct and ethics,
•
code of ethics for senior financial officers, and
•
information on how to communicate directly with our board of directors.
We will also provide printed copies of any of these documents to any stockholder free of charge upon request. In addition, the materials we file with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information about the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information that is filed electronically with the SEC.

18


Executive Officers
The names, ages and titles of our executive officers are:
Name
 
Age
 
Position
Phillip J. Weber
 
55
 
Chief Executive Officer
Charles D. Jehl
 
47
 
Chief Financial Officer and Treasurer
Bruce F. Dickson
 
62
 
Chief Real Estate Officer
David M. Grimm
 
55
 
Chief Administrative Officer, Executive Vice President, General Counsel and Secretary
Michael J. Quinley
 
54
 
President - Community Development
Phillip J. Weber has served as our Chief Executive Officer since September 2015. He has served as Chairman of the Real Estate Investment Committee since May 2013 and previously served as Executive Vice President - Water Resources from May 2013 to September 2015 and as Executive Vice President - Real Estate from 2009 to May 2013. Prior to joining Forestar, he served the Federal National Mortgage Association (Fannie Mae) as Senior Vice President - Multifamily from 2006 to October 2009, as Chief of Staff to the CEO from 2004 to 2006, as Chief of Staff to non-Executive Chairman of the Board and Corporate Secretary from 2005 to 2006, and as Senior Vice President, Corporate Development in 2005.
Charles D. Jehl has served as our Chief Financial Officer and Treasurer since September 2015. He previously served as our Executive Vice President - Oil and Gas from February 2015 to September 2015, as Executive Vice President - Oil and Gas Business Administration from 2013 to February 2015, and as Chief Accounting Officer from 2006 to 2013. Mr. Jehl served as Chief Operations Officer and Chief Financial Officer of Guaranty Insurance Services, Inc. from 2005 to 2006, and as Senior Vice President and Controller from 2000 to 2005. From 1989 to 1999, Mr. Jehl held various financial management positions within Temple-Inland’s financial services segment. Mr. Jehl is also a Certified Public Accountant.
Bruce F. Dickson has served as our Chief Real Estate Officer since March 2011. From 2009 through March 2011, he was the owner of Fairchild Investments LLC, a real estate investment firm. He served Standard Pacific Corp. as Southeast Region President from 2004 to 2009 and as Austin Division President from 2002 to 2004. From 1991 to 2001, he held region or division president positions with D.R. Horton, Inc., Milburn Homes and Continental Homes. His prior experience includes investment banking and financial services.
David M. Grimm has served as our Chief Administrative Officer since 2007, in addition to holding the offices of General Counsel and Secretary since 2006. Mr. Grimm served Temple-Inland Inc. as Group General Counsel from 2005 to 2006, Associate General Counsel from 2003 to 2005, and held various other legal positions from 1992 to 2003. Prior to joining Temple-Inland Inc., he was an attorney in private practice in Dallas, Texas. Mr. Grimm is also a Certified Public Accountant.
Michael J. Quinley has served as our President - Community Development since September 2015. He previously served as our Executive Vice President - Real Estate, East Region from 2011 to September 2015, as Executive Vice President - Eastern Region Real Estate Investments & Development from 2010 to 2011, and as Executive Vice President - Eastern Region Developments & Investments from 2008 to 2010. He has more than 30 years of prior real estate experience, including as CEO of Patrick Malloy Communities, as Senior Executive Vice President of Cousins Properties Incorporated and as Senior Vice President and CFO of Peachtree Corners Inc., all based in Atlanta.






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Item 1A.
Risk Factors.
General Risks Related to our Operations
Both our real estate and oil and gas businesses are cyclical in nature.
The operating results of our business segments reflect the general cyclical pattern of each segment. While the cycles of each industry do not necessarily coincide, demand and prices in each may drop substantially during the same period. Real estate development of residential lots is further influenced by new home construction activity, which has been volatile in recent years. Oil and gas may be further influenced by national and international commodity prices, principally for oil and gas. Cyclical downturns may materially and adversely affect our business, liquidity, financial condition and results of operations. All of our operations are impacted by both national and global economic conditions.
The real estate, oil and gas and natural resource industries are highly competitive and a number of entities with which we compete are larger and have greater resources, and competitive conditions may adversely affect our results of operations.
The real estate, oil and gas, and natural resources industries in which we operate are highly competitive and are affected to varying degrees by supply and demand factors and economic conditions, including changes in interest rates, new housing starts, home repair and remodeling activities, credit availability, consumer confidence, unemployment, housing affordability, changes in oil and gas prices, and federal energy policies.
The competitive conditions in the real estate industry may result in difficulties acquiring suitable land at acceptable prices, lower sales volumes and prices, increased development or construction costs and delays in construction and leasing. We compete with numerous regional and local developers for the acquisition, entitlement, and development of land suitable for development. We also compete with national, regional and local home builders who develop real estate for their own use in homebuilding operations, many of which are larger and have greater resources, including greater marketing budgets. Any improvement in the cost structure or service of our competitors will increase the competition we face.
We face intense competition from both major and independent oil and gas companies. Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil and gas companies. These companies also may have greater geologic or other technical expertise than we do.
Our business, financial condition and results of operations may be negatively affected by any of these factors.
We may be unable to successfully divest our non-core assets, which could adversely affect our results of operations or cash flows.
We have announced that we are focused on our core residential housing business, and that we intend to exit non-core, non-residential housing assets. The sale of non-core real estate assets may be impacted by market conditions outside of our control, such as capitalization rates, anticipated market demand and job growth, property location and other existing or anticipated competitive properties, interest rates, availability of financing, and other factors that we do not control. Additionally, the sale of non-core oil and gas assets may be impacted by oil and gas commodity prices, demand for similar assets, extraction costs, regulatory environment, and other factors that we do not control. Our ability to divest non-core assets, the timing for such divestments, and the prices we may ultimately receive may be impacted by the foregoing or other factors.
Our activities are subject to environmental regulations and liabilities that could have a negative effect on our operating results.
Our operations are subject to federal, state and local laws and regulations related to the protection of the environment. Compliance with these provisions or the promulgation of new environmental laws and regulations may result in delays, may cause us to invest substantial funds to ensure compliance with applicable environmental regulations and can prohibit or severely restrict timber harvesting, real estate development or mineral production activity in environmentally sensitive regions or areas.
Significant reductions in cash flow from slowing real estate, oil and gas or other natural resources market conditions could lead to higher levels of indebtedness, limiting our financial and operating flexibility.
We must comply with various covenants contained in our senior secured credit facility, the indentures governing our 3.75% convertible senior notes due 2020 (Convertible Notes), 4.50% senior amortizing notes due 2016 (Senior Amortizing Notes), 8.50% senior secured notes due 2022 (Senior Secured Notes) and any other existing or future debt arrangements. Significant reductions in cash flow from slowing real estate, oil and gas or other natural resources market conditions could require us to increase borrowing levels under our senior secured credit facility or to borrow under other debt arrangements and lead to higher levels of indebtedness, limiting our financial and operating flexibility, and ultimately limiting our ability to comply with our debt covenants, including the maintenance covenants under our senior secured credit facility. Realization of any of these factors could adversely affect our financial condition and results of operations.

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Restrictive covenants under our senior secured credit facility and indentures governing our 3.75% convertible senior notes, 4.50% senior amortizing notes and 8.50% senior secured notes may limit the manner in which we operate.
Our senior secured credit facility and indentures covering our Convertible Notes, Senior Amortizing Notes and Senior Secured Notes contain various covenants and conditions that limit our ability to, among other things:
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incur or guarantee additional debt;
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pay dividends or make distributions to our stockholders;
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repurchase or redeem capital stock or subordinated indebtedness;
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make loans, investments or acquisitions;
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incur restrictions on the ability of certain of our subsidiaries to pay dividends or to make other payments to us;
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enter into transactions with affiliates;
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create liens;
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merge or consolidate with other companies or transfer all or substantially all of our assets; and
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transfer or sell assets, including capital stock of subsidiaries.
As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Debt within some of our ventures may not be renewed or may be difficult or more expensive to replace.
As of December 31, 2015, our unconsolidated ventures had approximately $134.7 million of debt, of which $28.3 million was non-recourse to us. When debt within our ventures matures, some of our ventures may be unable to renew existing loans or secure replacement financing, or replacement financing may be more expensive. If our ventures are unable to renew existing loans or secure replacement financing, we may be required to contribute additional equity or elect to loan or contribute funds to our ventures, which could increase our risk or increase our borrowings under our senior secured credit facility, or both. If our ventures secure replacement financing that is more expensive, our profits may be reduced.
We may not be able to generate sufficient cash flow to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
As of December 31, 2015, we had approximately $390 million of consolidated debt outstanding. Our ability to make scheduled payments or to refinance current or future debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional debt or equity capital or restructure or refinance our indebtedness. We cannot be certain that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations.
Despite current indebtedness levels, we and our subsidiaries may be able to incur substantially more debt.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify.
Our business may suffer if we lose key personnel.
We depend to a large extent on the services of certain key management personnel. These individuals have extensive experience and expertise in our business segments in which they work. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled personnel in each of our business segments.
In addition, we have determined that certain of our assets are not part of our core residential housing business. We have retained advisors to sell a hotel in Austin and to market non-core oil and gas assets. Although we have implemented compensation arrangements designed to retain key personnel associated with operating non-core assets, we may be unable to retain all such personnel until all non-core assets have been divested.


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Risks Related to our Real Estate Operations
Reduced demand for new housing or commercial tracts in the markets where we operate could adversely impact our profitability.
The residential development industry is cyclical and is significantly affected by changes in general and local economic conditions, such as employment levels, availability of financing for home buyers, interest rates, consumer confidence and housing demand. Adverse changes in these conditions generally, or in the markets where we operate, could decrease demand for lots for new homes in these areas. Decline in housing demand could negatively affect our real estate development activities, which could result in a decrease in our revenues and earnings.
Furthermore, the market value of undeveloped land and lots held by us, including commercial tracts, can fluctuate significantly as a result of changing economic and real estate market conditions. If there are significant adverse changes in economic or real estate market conditions, we may have to hold land in inventory longer than planned. Inventory carrying costs can be significant and can result in losses or lower returns and adversely affect our liquidity.
Development of real estate entails a lengthy, uncertain and costly entitlement process.
Approval to develop real property entails an extensive entitlement process involving multiple and overlapping regulatory jurisdictions and often requiring discretionary action by local governments. This process is often political, uncertain and may require significant exactions in order to secure approvals. Real estate projects must generally comply with local land development regulations and may need to comply with state and federal regulations. The process to comply with these regulations is usually lengthy and costly, may not result in the approvals we seek, and can be expected to materially affect our real estate development activities, which may adversely affect our business, liquidity, financial condition and results of operations.
Our real estate development operations are currently concentrated in the major markets of Texas, and a significant portion of our undeveloped land holdings are concentrated in Georgia. As a result, our financial results are dependent on the economic growth and strength of those areas.
The economic growth and strength of Texas, where the majority of our real estate development activity is located, are important factors in sustaining demand for our real estate development activities. The recent sharp decline in oil prices may impact near-term job growth and housing demand in Texas, particularly in Houston, where the energy industry has generated significant job growth over the past several years. Further, the future economic growth and real estate development opportunities in broad area around Atlanta, Georgia may be adversely affected if its infrastructure, such as roads, utilities, and schools, are not improved to meet increased demand. There can be no assurance that these improvements will occur. As a result, any adverse impact to the economic growth and health, or infrastructure development, of those areas could materially adversely affect our business, liquidity, financial condition and results of operations.
Our real estate development operations are highly dependent upon national, regional and local home builders.
We are highly dependent upon our relationships with national, regional, and local home builders to purchase lots in our residential developments. If home builders do not view our developments as desirable locations for homebuilding operations, or if home builders are limited in their ability to conduct operations due to economic conditions, our business, liquidity, financial condition and results of operations will be adversely affected.
In addition, we enter into contracts to sell lots to home builders. A home builder could decide to delay purchases of lots in one or more of our developments due to adverse real estate conditions wholly unrelated to our areas of operations, such as the corporate decisions regarding allocation of limited capital or human resources. As a result, we may sell fewer lots and may have lower sales revenues, which could have an adverse effect on our business, liquidity, financial condition and results of operations.
Our strategic partners may have interests that differ from ours and may take actions that adversely affect us.
We enter into strategic alliances or venture relationships as part of our overall strategy for particular developments or regions. While these partners may bring development experience, industry expertise, financing capabilities, local credibility or other competitive attributes, they may also have economic or business interests or goals that are inconsistent with ours or that are influenced by factors unrelated to our business. We may also be subject to adverse business consequences if the market reputation or financial condition of a partner deteriorates, or if a partner takes actions inconsistent with our interest.
When we enter into a venture, we may rely on our venture partner to fund its share of capital commitments to the venture and to otherwise fulfill its operating and financial obligations. Failure of a venture partner to timely satisfy its funding or other obligations to the venture could require us to elect whether to increase our financial or other operating support of the venture in order to preserve our investment, which may reduce our returns or cause us to incur losses, or to not fund such obligations, which may subject the venture and us to adverse consequences or increase our financial exposure in the project.

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Delays or failures by governmental authorities to take expected actions could reduce our returns or cause us to incur losses on certain real estate development projects.
For certain projects, we rely on governmental utility and special improvement districts (SID) to issue bonds to reimburse us for qualified expenses, such as road and utility infrastructure costs. Bonds must be supported by district tax revenues, usually from ad valorem taxes. Slowing new home sales, decreasing real estate prices or difficult credit markets for bond sales can reduce or delay district bond sale revenues, causing such districts to delay reimbursement of our qualified expenses. Failure to receive timely reimbursement for qualified expenses could adversely affect our cash flows and reduce our returns or cause us to incur losses on certain real estate development projects.
Development and construction risks could impact our profitability.
We may develop and construct single family or multifamily communities as wholly-owned projects or through ventures with unaffiliated parties. Our development and construction activities may be exposed to the following risks:
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we may incur construction costs for a property that exceed original estimates due to increased materials, labor or other costs or unforeseen environmental or other conditions, which could make completion of the property uneconomical, and we may not be able to increase rents or sales to compensate for the increase in construction costs;
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we may be unable to complete construction and/or lease-up of a community on schedule and meet financial goals for development projects;
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an adverse incident during construction or development could adversely affect our ability to complete construction, conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, equipment, pollution or other environmental contamination, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation; and
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because occupancy rates and rents at a newly developed community may fluctuate depending on a number of factors, including market and economic conditions, we may be unable to meet our profitability goals for that community.
Possible difficulty of selling multifamily communities could limit our operational and financial flexibility.
Purchasers may not be willing to pay acceptable prices for multifamily communities that we wish to sell. If we are unable to sell multifamily communities or if we can only sell multifamily communities at prices lower than are generally acceptable, then we may receive lower returns than expected or may have to take on additional leverage in order to provide adequate capital to execute our business strategy.
Increased competition and increased affordability of residential homes could limit our ability to retain residents, lease apartments or increase or maintain rents.
Our multifamily communities compete with numerous housing alternatives in attracting residents, including other multifamily communities and single-family rental homes, as well as owner occupied single and multifamily homes. Competitive housing could adversely affect our ability to retain residents, lease apartments and increase or maintain rents.
Failure to succeed in new markets may limit our growth.
We may from time to time commence development activity or make acquisitions outside of our existing market areas if appropriate opportunities arise. Our historical experience in existing markets does not ensure that we will be able to operate successfully in new markets. We may be exposed to a variety of risks if we choose to enter new markets, including, among others:
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an inability to accurately evaluate local housing market conditions and local economies;
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an inability to obtain land for development or to identify appropriate acquisition opportunities;
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an inability to hire and retain key personnel;
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an inability to successfully integrate operations; and
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lack of familiarity with local governmental and permitting procedures.
Risks Related to our Oil and Gas Operations
Volatile oil and gas prices could adversely affect our cash flows and results of operations.
Our cash flows and results of operations are dependent in part on oil and gas prices, which are volatile. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48 percent lower than in 2014 due to growth in global oil inventories and weakening global demand, particularly in Asia. There is a risk that commodity prices could remain depressed for sustained periods.  We can be impacted by short-term changes in commodity prices. Oil and gas prices also

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impact the amounts we receive for selling and renewing our mineral leases. Moreover, oil and gas prices depend on factors we cannot control, such as: changes in foreign and domestic supply and demand for oil and gas; actions by the Organization of Petroleum Exporting Countries (OPEC); weather; political conditions in other oil-producing countries, including the possibility of insurgency or war in such areas; prices of foreign exports; domestic and international drilling activity; price and availability of alternate fuel sources; the value of the U.S. dollar relative to other major currencies; the level and effect of trading in commodity markets; the effect of worldwide energy conservation measures and governmental regulations. Any substantial or extended decline in the price of oil and gas could have a negative impact on our business, liquidity, financial condition and results of operations.
Our operations are subject to the numerous risks of oil and gas drilling and production activities.
Oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, ruptures, discharges of toxic gases, underground migration and surface spills or mishandling of any toxic fracture fluids, including chemical additives. In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively affect our operations. If any of these or other similar industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, environmental damage, regulatory investigation, enforcement actions and penalties, and restriction or suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves and may have a material adverse effect on our financial condition.
The process of estimating oil and gas reserves is complex involving decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes and quantities of recoverable oil and gas reserves might vary from those estimated. Any variance could materially affect the estimated quantities and present value of proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, development, prevailing oil and gas prices and other factors, many of which are beyond our control. Such adjustments could negatively impact our ability to obtain financing.
The estimates of our reserves as of December 31, 2015 are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the standardized measure thereof for our oil and gas interests are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2015. The average realized sales prices as of such date used for purposes of such estimates were $2.59 per thousand cubic feet (Mcf) of gas and $50.28 per barrel of oil. The December 31, 2015 estimates also assume that the working interest owners will make future capital expenditures which are necessary to develop and realize the value of proved reserves.
The standardized measure of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves.
Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. As required by SEC regulations, we base our present value of estimated future oil and gas revenues on prices and costs in effect at the time of the estimate. However, actual future net cash flows from our properties will be affected by numerous factors not subject to our control and will be affected by factors such as:
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decisions and activities of the well operators;
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supply of and demand for oil and gas;
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actual prices we receive for oil and gas;
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actual operating costs;
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the amount and timing of capital expenditures;
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the amount and timing of actual production; and
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changes in governmental regulations or taxation.
The timing of production will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow, which is required

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by the SEC, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Hydraulic fracturing, the process used for extracting oil and gas from shale and other formations, and other subsurface injections have come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of extractive activities.
Hydraulic fracturing is the primary production method used to extract hydrocarbon reserves located in many of the unconventional oil and gas plays in the United States. Following years of study, the United States Environmental Protection Agency (EPA) in June 2015 issued a draft report regarding the potential impacts of hydraulic fracturing on drinking water resources. The draft report did not find evidence of widespread, systemic impacts on drinking water resources, but did identify spills and other mechanisms associated with hydraulic fracturing that could impact drinking water resources. The report, when finalized, may influence federal and state legislative and regulatory developments. Other federal regulatory developments in 2015 include (i) new rules by EPA which tightened the National Ambient Air Quality Standard (NAAQS) for ozone, which could result in additional mandatory controls on oil and gas sector volatile organic compound (VOC) emissions; and (ii) new rules by the U.S. Department of the Interior, Bureau of Land Management addressing hydraulic fracturing on federal and tribal lands, including new requirements for well casing, cementing, wastewater disposal, and disclosure of chemicals used in well completions.  In addition, in September 2015, EPA proposed, as part of the agency’s Climate Action Plan, new regulations to further reduce methane emissions from the oil and gas industry, including during well completions and hydraulic fracturing, and asserted that the industry is one of the largest emitters of methane, a green-house gas.
 Hydraulic fracturing is also extensively regulated at the state and local level and has been subject to temporary or permanent moratoria in some states, although in 2015, it has not been subject to such moratoria in the states and locations of our oil and gas operations or minerals. Also under public and governmental scrutiny is subsurface injection of water or other produced fluids from drilling or hydraulic fracturing processes due to potential environmental and physical impacts, including possible links to swarms of earthquakes occurring in areas near certain injection wells. For example, the Railroad Commission of Texas has hired a staff seismologist to study seismic activity and in 2014 adopted new rules for injection wells aimed at reducing the potential for earthquakes. Tighter regulation of injection wells could increase our costs of operations, including costs for well completions.
Depending on legislation that may ultimately be enacted or regulations that may be adopted at the federal, state and local levels, exploration, exploitation and production activities that entail hydraulic fracturing or other subsurface injection could be subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays, increased costs and other burdens that could delay the development of oil and gas resources from formations that are not commercial without the use of these techniques. This could have a material effect on our oil and gas production operations and on the operators conducting activities on our minerals and on the cash flows we receive from them.
Our reserves and production will decline from their current levels.
The rate of production from oil and gas properties generally declines as reserves are produced. Our reserves will decline as they are produced which could materially and adversely affect our future cash flow, liquidity and results of operations.
Our oil and gas production may be subject to interruptions that could have a material and adverse effect on us.
Our oil and gas production may be interrupted, or shut in, from time to time for various reasons, including as a result of accidents, natural disasters, weather conditions, loss of gathering, processing, compression or transportation facility access or field labor issues, or intentionally as a result of market conditions such as oil and gas prices that the operators of our mineral leases, whose decisions we do not control, deem uneconomic. If a substantial amount of production is interrupted, our business, liquidity and results of operations could be materially and adversely affected.
We do not insure against all potential losses and could be materially and adversely affected by unexpected liabilities.
The exploration for, and production of, oil and gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, result in injury or death, and damage property and the environment. We maintain insurance against many, but not all, potential losses or liabilities arising from operations on our property in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. In addition, we require third party operators to maintain customary and commercially practicable types and limits of insurance, but potential losses or liabilities may not be covered by such third party’s insurance which may subject us to liability as the mineral estate owner. The occurrence of any of these events and any costs or liabilities incurred as a result of such events could have a material adverse effect on our business, financial condition and results of operations.

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We have limited control over the activities on properties we do not operate and are unable to ensure their proper operation and profitability.
Many of the properties in which we have working interests are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially and adversely affect our business, liquidity, financial condition and results of operations.
In addition, operators determine when and where to drill wells and we have no influence over these decisions. The success and timing of the drilling and development activities on our non-operated properties therefore depends upon a number of factors currently outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology, and the operators of our properties may not have the same financial and other resources as other oil and gas companies with whom they compete. Further, new wells may not be productive or may not produce at a level to enable us to recover all or any portion of our capital investment where we have a non-operating working interest.
The ability to sell and deliver oil and gas produced from wells on our mineral leasehold interests could be materially and adversely affected if adequate gathering, processing, compression and transportation services are not obtained.
The sale of oil and gas produced from wells on our mineral leasehold interests depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities owned or operated by third parties. These facilities may be temporarily unavailable due to market conditions, mechanical reasons or other factors or conditions, and may not be available in the future on terms the operator considers acceptable, if at all. In addition, federal, state and provincial governments in the United States and Canada have issued or are considering issuance of additional regulations governing transportation of crude oil and its byproducts by rail. Such regulations could increase the cost of transportation or limit the availability of suitable rail cars or both. Any significant change in market or other conditions affecting these facilities or the availability of these facilities, including due to the failure or inability to obtain access to these facilities on terms acceptable to the operator or at all, could materially and adversely affect our business, liquidity, financial condition and results of operations.
A significant portion of our Louisiana owned net mineral acres are subject to prescription of non-use under Louisiana law.
A significant portion of our Louisiana owned net mineral acres were severed from surface ownership and retained by creation of one or more mineral servitudes shortly before our 2007 spin-off. Under Louisiana law, a mineral servitude that is not producing minerals or which has not been the subject of good-faith drilling operations will cease to burden the property upon the tenth anniversary of the date of its creation. Upon such event, the mineral rights effectively will revert to the surface owner and we will no longer own the right to lease, explore for or produce minerals from such acreage. Approximately 40,000 acres of our Louisiana owned net mineral acres may revert to the surface owner in 2017 unless drilling operations are commenced prior to the tenth anniversary of severance from the surface.
Weather, climate and climate change regulation may have a significant and adverse impact on us.
Demand for natural gas is, to a significant degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities produced from gas wells and, in turn, our cash flow and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for gas, higher inventory (as less gas is used to heat residences and businesses) and, as a result, relatively lower prices for gas production.
Drilling for and production of oil and gas also can be impacted by weather and climate. Specifically, cold temperatures or significant precipitation or both can restrict operation of machinery or access to well sites by personnel or equipment. These restrictions may reduce our production and, in turn, our cash flow and results of operations.
The EPA has proposed regulations for the purpose of restricting greenhouse gas emissions from stationary sources. Such regulatory and legislative proposals to restrict greenhouse gas emissions, or to address climate change generally, could increase our operating costs as well operators incur costs to comply with new rules. Such increased costs may include installation of new or expanded emissions control systems, purchase of allowances to authorize greenhouse gas emissions, and increased taxes. Regulation of greenhouse gases may also occur at the state level. Depending on legislation that may ultimately be enacted or regulations that may be adopted at the Federal or state level, there could be increased costs, operational delays and other burdens affecting the oil and gas industry. This could have a material effect on our oil and gas production operations and on the operators conducting activities on our properties and on cash flows we receive from them.

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Risks Related to our Other Natural Resources Operations
Our water interests may require governmental permits, the consent of third parties and/or completion of significant transportation infrastructure prior to commercialization, all of which are dependent on the actions of others.
Many jurisdictions require governmental permits to withdraw and transport water for commercial uses, the granting of which may be subject to discretionary determinations by such jurisdictions regarding necessity. In addition, we do not own the executory rights related to our non-participating royalty interest, and as a result, third-party consent from the executor rights owner(s) would be required prior to production. The process to obtain permits can be lengthy, and governmental jurisdictions or third parties from whom we seek permits or consent may not provide the approvals we seek. We may be unable to secure buyers at commercially economic prices for water that we have a right to extract and transport, and transportation infrastructure across property not owned or controlled by us is required for transport of water prior to commercial use. Such infrastructure can require significant capital and may also require the consent of third parties. We may not have cost effective means to transport water from property we own, lease or manage to buyers. As a result, we may lose some or all of our investment in water assets, or our returns may be diminished.
Our ability to harvest and deliver timber may be affected by our sales of timberland and may be subject to other limitations, which could adversely affect our operations.
Sales of our timberland reduce the amount of timber that we have available for harvest. In addition, weather conditions, timber growth cycles, access limitations, availability of contract loggers and haulers, and regulatory requirements associated with the protection of wildlife and water resources may restrict harvesting of timberlands as may other factors, including damage by fire, insect infestation, disease, prolonged drought, flooding and other natural disasters. Although damage from such natural causes usually is localized and affects only a limited percentage of the timber, there can be no assurance that any damage affecting our timberlands will in fact be so limited. As is common in the forest products industry, we do not maintain insurance coverage with respect to damage to our timberlands.
The revenues, income and cash flow from operations for our other natural resources segment are dependent to a significant extent on the pricing of our products and our continued ability to harvest timber at adequate levels.
Other Risks
The market price of and trading volume of our shares of common stock may be volatile.
The market price of our shares of common stock has fluctuated substantially and may continue to fluctuate in response to the following factors, many of which are beyond our control:
•
fluctuations in our operating results, including results that vary from expectations of management, analysts and investors;
•
changes in investors’ and analysts’ perception of the business risks and conditions of our business;
•
broader market fluctuations;
•
general financial, economic and political conditions;
•
regulatory changes affecting our industry generally or our businesses and operations;
•
environmental regulations and liabilities that could have a negative effect on our operating results;
•
announcements of strategic developments, acquisitions, financings and other material events by us or our competitors;
•
the sale of a substantial number of shares of our common stock held by existing security holders in the public market; and
•
general conditions in the real estate and mineral resources industries.
The stock markets in general have experienced extreme volatility that has at times been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock, make it difficult to predict the market price of our common stock in the future and cause the value of our common stock to decline.
Provisions of Delaware law, our charter documents, the indentures governing the 3.75% convertible senior notes, 8.50% senior secured notes and the stock purchase contracts under the 6.00% tangible equity units may impede or discourage a takeover, which could cause the market price of our common stock to decline.
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders. In addition, our board of directors has the power, without stockholder approval, to designate the terms of one or more series of

27


preferred stock and issue shares of preferred stock. These and other impediments to third party acquisition or change of control could limit the price investors are willing to pay for shares of our common stock, which could in turn reduce the market price of our common stock. In addition, upon the occurrence of a fundamental change under the terms of the convertible senior notes, the senior secured notes or the tangible equity units, certain repurchase rights and early settlement rights would be triggered under the indentures governing the convertible senior notes, senior secured notes and the stock purchase contracts under the 6.00% tangible equity units, respectively. In such event, the increase of the conversion or early settlement rate, as applicable, in connection with certain make-whole fundamental change transactions under the terms of the convertible senior notes or the stock purchase contracts, respectively, could discourage a potential acquirer.
Item 1B.
Unresolved Staff Comments.
None.

Item 2.
Properties.
Our principal executive offices are located in Austin, Texas, where we recently commenced the process to reduce our office space from approximately 32,000 to 18,600 square feet. We also lease office space in Atlanta, Georgia; Dallas, Texas; Denver, Colorado; and Lufkin, Texas. We believe these offices are suitable for conducting our business.
For a description of our properties in our real estate, oil and gas and other natural resources segments, see “Business — Real Estate”, “Business — Oil and Gas” and “Business — Other Natural Resources”, respectively, in Part I, Item 1 of this Annual Report on Form 10-K.
 
Item 3.
Legal Proceedings.
We are involved directly or through ventures in various legal proceedings that arise from time to time in the ordinary course of doing business. We believe we have established adequate reserves for any probable losses and that the outcome of any of the proceedings should not have a material adverse effect on our financial position or long-term results of operations or cash flows. It is possible, however, that charges related to these matters could be significant to results of operations or cash flow in any single accounting period.

Item 4.
Mine Safety Disclosures.
Not Applicable.

PART II

Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Our common stock is traded on the New York Stock Exchange. The high and low sales prices in each quarter in 2015 and 2014 were:
 
2015
 
2014
 
Price Range
 
Price Range
 
High
 
Low
 
High
 
Low
First Quarter
$
15.91

 
$
13.27

 
$
21.30

 
$
17.67

Second Quarter
$
16.29

 
$
13.16

 
$
19.22

 
$
16.70

Third Quarter
$
13.67

 
$
11.98

 
$
20.10

 
$
17.72

Fourth Quarter
$
14.59

 
$
10.58

 
$
17.68

 
$
14.42

For the Year
$
16.29

 
$
10.58

 
$
21.30

 
$
14.42


28


Shareholders
Our stock transfer records indicated that as of February 29, 2016, there were approximately 3,244 holders of record of our common stock.
Dividend Policy
We currently intend to retain any future earnings to support our business. The declaration and payment of any future dividends will be at the discretion of our Board of Directors after taking into account various factors, including without limitation, our financial condition, earnings, capital requirements of our business, the terms of any credit agreements or indentures to which we may be a party at the time, legal requirements, industry practice, and other factors that our Board of Directors deems relevant.
Issuer Purchases of Equity Securities (a) 
Period
Total
Number of
Shares
Purchased (b)
 
Average
Price Paid
per Share
 
Total Number
of Shares
Purchased as
Part of
Publicly
Announced
Plan or
Programs
 
Maximum
Number of
Shares That
May Yet be
Purchased
Under the
Plans or
Programs
Month 10 (10/1/2015 — 10/31/2015)
693

 
$
14.39

 
—

 
3,506,668

Month 11 (11/1/2015 — 11/30/2015)
2,192

 
$
12.80

 
—

 
3,506,668

Month 12 (12/1/2015 — 12/31/2015)
—

 
$
—

 
—

 
3,506,668

Total
2,885

 
$
13.18

 
—

 
 
 _____________________
(a) 
On February 11, 2009, we announced that our Board of Directors authorized the repurchase of up to 7,000,000 shares of our common stock. We have purchased 3,493,332 shares under this authorization, which has no expiration date. We did not make any repurchases in 2015. We have no repurchase plans or programs that expired during the period covered by the table above and no repurchase plans or programs that we intend to terminate prior to expiration or under which we no longer intend to make further purchases.
(b) 
Includes shares withheld to pay taxes in connection with vesting of restricted stock awards and exercises of stock options.

29


Performance Graph
Our peer group consists of the following real estate and oil and gas companies: Alexander & Baldwin, Inc., AV Homes Inc., Approach Resources, Inc., Consolidated-Tomoka Land Co., Cousins Properties Incorporated, Contango Oil and Gas Co., Goodrich Petroleum Corp., Magnum Hunter Resources Corp., Matador Resources Co., Penn Virginia Corp., Petroquest Energy Inc., Post Properties, Inc., Potlatch Corporation, PS Business Parks, Inc., Resolute Energy Corp., The St. Joe Company, and Tejon Ranch Co. There were no changes to the peer group in 2015.
Pursuant to SEC rules, returns of each of the companies in the Peer Index are weighted according to the respective company’s stock market capitalization at the beginning of each period for which a return is indicated.

30


Item 6.
Selected Financial Data.
 
For the Year
 
2015
 
2014
 
2013
 
2012
 
2011
 
(In thousands, except per share amount)
Revenues:
 
 
 
 
 
 
 
 
 
Real estate
$
202,830

 
$
213,112

 
$
248,011

 
$
120,115

 
$
106,168

Oil and gas
52,939

 
84,300

 
72,313

 
44,220

 
24,448

Other natural resources
6,652

 
9,362

 
10,721

 
8,256

 
4,957

Total revenues
$
262,421

 
$
306,774

 
$
331,045

 
$
172,591

 
$
135,573

Segment earnings (loss):
 
 
 
 
 
 
 
 
 
Real estate (a)
$
67,678

 
$
96,906

 
$
68,454

 
$
53,582

 
$
(25,704
)
Oil and gas (b)
(184,396
)
 
(22,686
)
 
18,859

 
26,608

 
19,783

Other natural resources
(608
)
 
5,499

 
6,507

 
29

 
(1,867
)
Total segment earnings (loss)
(117,326
)
 
79,719

 
93,820

 
80,219

 
(7,788
)
Items not allocated to segments:
 
 
 
 
 
 
 
 
 
General and administrative expense (c)
(24,802
)
 
(21,229
)
 
(20,597
)
 
(25,176
)
 
(20,110
)
Share-based compensation expense
(4,474
)
 
(3,417
)
 
(16,809
)
 
(14,929
)
 
(7,067
)
Gain on sale of assets (d)
—

 
—

 
—

 
16

 
61,784

Interest expense
(34,066
)
 
(30,286
)
 
(20,004
)
 
(19,363
)
 
(17,012
)
Other corporate non-operating income
256

 
453

 
119

 
191

 
368

(Loss) Income before taxes
(180,412
)
 
25,240

 
36,529

 
20,958

 
10,175

Income tax expense (e)
(32,635
)
 
(8,657
)
 
(7,208
)
 
(8,016
)
 
(3,021
)
Net income (loss) attributable to Forestar Group Inc.
$
(213,047
)
 
$
16,583

 
$
29,321

 
$
12,942

 
$
7,154

Net income (loss) per common share
$
(6.22
)
 
$
0.38

 
$
0.80

 
$
0.36

 
$
0.20

Average diluted shares outstanding (f)
34,266

 
43,596

 
36,813

 
35,482

 
35,781

At year-end:
 
 
 
 
 
 
 
 
 
Assets
$
980,513

 
$
1,258,199

 
$
1,172,152

 
$
918,434

 
$
794,857

Debt
389,782

 
432,744

 
357,407

 
294,063

 
221,587

Noncontrolling interest
2,515

 
2,540

 
5,552

 
4,059

 
1,686

Forestar Group Inc. shareholders’ equity
501,600

 
707,202

 
709,845

 
529,488

 
509,526

Ratio of total debt to total capitalization
44
%
 
38
%
 
33
%
 
36
%
 
30
%
 _____________________
(a) 
Real estate segment earnings (loss) include non-cash impairments of $1,044,000 in 2015, $399,000 in 2014, $1,790,000 in 2013 and $45,188,000 in 2011. Segment earnings also includes gain on sale of assets of $1,585,000 in 2015, $25,981,000 in 2014 and $25,273,000 in 2012. Real estate segment earnings (loss) also include the effects of net (income) loss attributable to noncontrolling interests.
(b) 
Oil and gas segment earnings (loss) includes non-cash impairment charges of $164,831,000 in 2015, $32,665,000 in 2014 and $473,000 in 2013 related to proved properties and unproved leasehold interests. Oil and gas segment earnings (loss) also includes losses of $706,000 in 2015 and gains of $8,526,000 in 2014 associated with sale of oil and gas properties.
(c) 
General administrative expense includes severance-related charges of $3,314,000 related to departures of our former Chief Executive Officer (CEO) and Chief Financial Officer (CFO) in 2015, $6,323,000 in costs associated with our acquisition of Credo in 2012 and $3,187,000 associated with proposed private debt offerings that we withdrew as a result of deterioration of terms available to us in the credit markets in 2011.
(d) 
Gain on sale of assets in 2011 represents gains from timberland sales in accordance with our strategic initiatives announced first quarter 2009 and completed in 2011.
(e) 
In 2015, income tax expense includes an expense of $97,068,000 for valuation allowance on a portion of our deferred tax asset that was determined to be more likely than not to be unrealizable. In 2013, income tax expense includes a benefit from recognition of $6,326,000 of previously unrecognized tax benefits upon lapse of the statute of limitations for a previously reserved tax position.
(f) 
Our 2015 weighted average diluted shares outstanding excludes dilutive effect of equity awards and 7,857,000 shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units issued in 2013, due to our net loss attributable to Forestar Group Inc.

31


Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Caution Concerning Forward-Looking Statements
This Annual Report on Form 10-K and other materials we have filed or may file with the Securities and Exchange Commission contain “forward-looking statements” within the meaning of the federal securities laws. These forward-looking statements are identified by their use of terms and phrases such as “believe,” “anticipate,” “could,” “estimate,” “likely,” “intend,” “may,” “plan,” “expect,” and similar expressions, including references to assumptions. These statements reflect our current views with respect to future events and are subject to risk and uncertainties. We note that a variety of factors and uncertainties could cause our actual results to differ significantly from the results discussed in the forward-looking statements. Factors and uncertainties that might cause such differences include, but are not limited to:
•
general economic, market or business conditions in Texas or Georgia, where our real estate activities are concentrated, or on a national or global scale;
•
our ability to achieve some or all of our strategic initiatives;
•
the opportunities (or lack thereof) that may be presented to us and that we may pursue;
•
our ability to hire and retain key personnel;
•
future residential or commercial entitlements, development approvals and the ability to obtain such approvals;
•
obtaining approvals of reimbursements and other payments from special improvement districts and timing of such payments;
•
accuracy of estimates and other assumptions related to investment in and development of real estate, the expected timing and pricing of land and lot sales and related cost of real estate sales, impairment of long-lived assets, income taxes, share-based compensation, oil and gas reserves, revenues, capital expenditures and lease operating expense accruals associated with our non-core oil and gas working interests, and depletion of our non-core oil and gas properties;
•
the levels of resale housing inventory in our mixed-use development projects and the regions in which they are located;
•
fluctuations in costs and expenses, including impacts from shortages in materials or labor;
•
demand for new housing, which can be affected by a number of factors including the availability of mortgage credit, job growth, fluctuations in commodity prices;
•
demand for multifamily communities, which can be affected by a number of factors including local markets and economic conditions;
•
competitive actions by other companies;
•
changes in governmental policies, laws or regulations and actions or restrictions of regulatory agencies;
•
risks associated with oil and gas exploration, drilling and production activities;
•
fluctuations in oil and gas commodity prices;
•
government regulation of exploration and production technology, including hydraulic fracturing;
•
the results of financing efforts, including our ability to obtain financing with favorable terms, or at all;
•
our ability to make interest and principal payments on our debt and satisfy the other covenants contained in our senior secured credit facility, indentures and other debt agreements;
•
our partners’ ability to fund their capital commitments and otherwise fulfill their operating and financial obligations;
•
the effect of limitations, restrictions and natural events on our ability to harvest and deliver timber;
•
inability to obtain permits for, or changes in laws, governmental policies or regulations affecting, water withdrawal or usage; and
•
the final resolutions or outcomes with respect to our contingent and other liabilities related to our business.
Other factors, including the risk factors described in Item 1A of this Annual Report on Form 10-K, may also cause actual results to differ materially from those projected by our forward-looking statements. New factors emerge from time to time and it is not possible for us to predict all such factors, nor can we assess the impact of any such factor on our business or the extent

32


to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, we expressly disclaim any obligation or undertaking to disseminate any updates or revisions to any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.
Key Initiatives
•
Reducing costs across our entire organization,
•
Reviewing entire portfolio of assets,
•
Reviewing capital structure; and
•
Providing additional information.

Results of Operations for the Years Ended 2015, 2014 and 2013
A summary of our consolidated results by business segment follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Revenues:
 
 
 
 
 
Real estate
$
202,830

 
$
213,112

 
$
248,011

Oil and gas
52,939

 
84,300

 
72,313

Other natural resources
6,652

 
9,362

 
10,721

Total revenues
$
262,421

 
$
306,774

 
$
331,045

Segment earnings (loss):
 
 
 
 
 
Real estate
$
67,678

 
$
96,906

 
$
68,454

Oil and gas
(184,396
)
 
(22,686
)
 
18,859

Other natural resources
(608
)
 
5,499

 
6,507

Total segment earnings (loss)
(117,326
)
 
79,719

 
93,820

Items not allocated to segments:
 
 
 
 
 
General and administrative expense
(24,802
)
 
(21,229
)
 
(20,597
)
Share-based and long-term incentive compensation expense
(4,474
)
 
(3,417
)
 
(16,809
)
Interest expense
(34,066
)
 
(30,286
)
 
(20,004
)
Other corporate non-operating income
256

 
453

 
119

Income (loss) before taxes
(180,412
)
 
25,240

 
36,529

Income tax expense
(32,635
)
 
(8,657
)
 
(7,208
)
Net income (loss) attributable to Forestar Group Inc.
$
(213,047
)
 
$
16,583

 
$
29,321


33


Significant aspects of our results of operations follow:
2015
•
Real estate segment earnings declined principally due to gain on sale of assets of $25,981,000 in 2014 compared with $1,585,000 in 2015, lower undeveloped land sales and decreased residential lot sales activity. Segment earnings were positively impacted by higher commercial and residential tract sales and sale of Midtown Cedar Hill, a 354-unit multifamily property near Dallas for $42,880,000, which generated segment earnings of $9,265,000.
•
Oil and gas segment loss was principally due to non-cash charges of $175,696,000 driven by lower current and projected future oil and gas prices, which included impairments of $107,140,000 for proved oil and gas properties and $57,691,000 for unproved leasehold interests, and exploratory dry hole costs and pre-drilling costs of $10,865,000. Segment earnings were negatively impacted by lower realized oil and gas prices despite a 19 percent increase in production volumes. In addition, 2015 results included $2,047,000 of employee severance and retention bonus costs as part of our initiative to significantly reduce oil and gas operating costs and a lease termination charge of $1,750,000 associated with closure of our office in Fort Worth.
•
General and administrative expense increased principally as a result of severance-related charges of $3,314,000 related to departures of our former Chief Executive Officer (CEO) and Chief Financial Officer (CFO).
•
Interest expense increased primarily due to higher average borrowing rates and increased average debt outstanding.
2014
•
Real estate segment earnings benefited from increased undeveloped land sales generating earnings of $29,895,000, a $10,476,000 gain associated with a non-monetary exchange of leasehold timber rights for 5,400 acres of undeveloped land with a partner in a consolidated venture, a $7,610,000 gain associated with the acquisition of our partner's interest in the Eleven multifamily venture, higher residential lot sales activity and a $6,577,000 gain associated with $46,500,000 of bond proceeds we received from the Cibolo Canyons Special Improvement District.
•
Oil and gas segment earnings decreased principally due to non-cash impairment charges of $17,130,000 for unproved leasehold interests and $15,535,000 for proved oil and gas properties, higher exploration costs and lower oil prices, as well as lower oil and gas production volumes associated with royalty interests and reduced lease bonus and delay rental payments received from our owned mineral interests. These factors were partially offset by higher working interest production volumes attributable to our exploration and production operations and gains of $8,526,000 primarily related to the sale of oil and gas properties in Oklahoma and North Dakota.
•
Other natural resources segment earnings declined principally due to lower fiber volumes, which were partially offset by gains of $3,531,000 primarily related to partial terminations of a timber lease related to land sold from a consolidated venture near Atlanta, Georgia.
•
Share-based compensation decreased principally as result of a 28% decrease in our stock price since year-end 2013 and its impact on cash-settled awards.
•
Interest expense increased primarily due to higher average borrowing rates and increased debt outstanding.
2013
•
Real estate segment earnings benefited from the sale of Promesa, a 289-unit multifamily property we developed in Austin, for $41,000,000, which generated approximately $10,881,000 in segment earnings. In addition, segment earnings also benefited from increased residential lot sales activity, residential and commercial tract sales and interest income associated with a loan we hold secured by a mixed-use community in Houston.
•
Oil and gas segment earnings decreased principally when compared with 2012 due to lower oil and gas production volumes associated with royalty interests and reduced lease bonus and delay rental payments received from our owned mineral interests, which were partially offset by higher working interest production volumes and prices attributable to our exploration and production operations principally as result of our acquisition of Credo in third quarter 2012.
•
Other natural resources segment earnings benefited from higher levels of timber harvesting activity driven by increased customer demand compared to 2012. In addition, segment earnings also benefited from a $3,828,000 gain from a partial termination of a timber lease related to land sold from a consolidated venture near Atlanta, Georgia.

34


•
Share-based compensation increased principally as result of our higher stock price in 2013 and its impact on cash-settled awards.
Current Market Conditions
Sales of new U.S. single-family homes rose to a seven-year high in December 2015, on a seasonally adjusted basis, but remain well below historical levels. Inventories of new homes are near historically low levels in many areas. In addition, declining finished lot inventories and limited supply of economically developable raw land has increased demand for our developed lots. However, national and global economic weakness and uncertainty, and a restrictive mortgage lending environment continue to threaten a robust recovery in the housing market, despite low interest rates. Multifamily market conditions continue to be strong, with many markets experiencing healthy occupancy levels and positive rent growth. This improvement has been driven primarily by limited housing inventory, reduced single-family mortgage credit availability, and the increased propensity to rent among the 18 to 34 year old demographic of the U.S. population.
Global supply and demand fundamentals for crude oil at year-end 2015 remained out of balance with high global and domestic inventories and slower global growth. West Texas Intermediate (WTI) oil prices averaged $48.66 per Bbl in 2015, nearly 48% lower than in 2014, and ended 2015 at $37.13 per Bbl. OPEC continues to produce at record high levels, focused on maintaining market share, and the lifting of sanctions against Iran introduced additional supply into the global market. Estimates for global demand growth continue to be tempered and could extend the global supply glut, resulting in an extended period of low crude oil pricing.
Average gas prices were 40 percent lower than 2014 and December 2015 spot prices reached the lowest levels since 1999. Despite a lower number of operating rigs, gas production in the United States increased by approximately 6 percent over 2014 levels primarily attributable to gains in drilling efficiencies.
Business Segments
We manage our operations through three business segments:
•
Real estate,
•
Oil and gas, and
•
Other natural resources.
We evaluate performance based on segment earnings (loss) before unallocated items and income taxes. Segment earnings (loss) consist of operating income (loss), equity in earnings of unconsolidated ventures’, gain on sale of assets, interest income on loans secured by real estate and net (income) loss attributable to noncontrolling interests. Items not allocated to our business segments consist of general and administrative expenses, share-based and long-term compensation, gain on sale of strategic timberland, interest expense and other corporate non-operating income and expense. The accounting policies of the segments are the same as those described in the accounting policy note to the consolidated financial statements.
We operate in cyclical industries. Our operations are affected to varying degrees by supply and demand factors and economic conditions including changes in interest rates, availability of mortgage credit, consumer and home builder sentiment, new housing starts, real estate values, employment levels, changes in the market prices for oil, gas and timber, and the overall strength or weakness of the U.S. economy.

Real Estate
We own directly or through ventures interests in 58 residential and mixed-use projects comprised of 7,000 acres of real estate located in 11 states and 15 markets. Our real estate segment secures entitlements and develops infrastructure on our lands, primarily for single-family residential and mixed-use communities. We own 89,000 acres of non-core timberland and undeveloped land in a broad area around Atlanta, Georgia, with the balance located primarily in Texas. We own and manage our projects either directly or through ventures. Our real estate segment revenues are principally derived from the sales of residential single-family lots and tracts, undeveloped land and commercial real estate and from the operation of income producing properties, primarily a hotel and multifamily properties.

35


A summary of our real estate results follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Revenues
$
202,830

 
$
213,112

 
$
248,011

Cost of sales
(113,891
)
 
(123,764
)
 
(156,794
)
Operating expenses
(40,502
)
 
(34,121
)
 
(31,952
)
 
48,437

 
55,227

 
59,265

Interest income on loan secured by real estate
2,750

 
8,135

 
6,840

Gain on sale of assets
1,585

 
25,981

 
—

Equity in earnings of unconsolidated ventures
15,582

 
8,068

 
8,089

Less: Net income attributable to noncontrolling interests
(676
)
 
(505
)
 
(5,740
)
Segment earnings
$
67,678

 
$
96,906

 
$
68,454

Revenues in our owned and consolidated ventures consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Residential real estate
$
87,771

 
$
119,308

 
$
107,858

Commercial real estate
5,390

 
2,717

 
18,338

Undeveloped land
22,851

 
46,554

 
22,757

Commercial and income producing properties
82,808

 
41,440

 
95,327

Other
4,010

 
3,093

 
3,731

 
$
202,830

 
$
213,112

 
$
248,011

Residential real estate revenues principally consist of the sale of single-family lots to local, regional and national homebuilders. In 2015, residential real estate revenues decreased primarily due to lower lot sales activity due to construction and inspection delays associated with abnormally wet weather conditions. In addition, in 2015, we sold 1,062 residential tract acres for $11,223,000 generating segment earnings of $5,489,000, compared with 936 acres of residential tracts for $7,996,000 generating segment earnings of $2,988,000 in 2014.
The timing of commercial real estate revenues can vary depending on the demand, mix, project life-cycle, size and location of the project. In 2015, our commercial tract sales revenue increased principally due to higher average sales price of tracts sold. In 2015, we sold 31 commercial acres for $5,542,000 from our owned and consolidated projects, generating earnings of $3,345,000, compared with 21 commercial acres for $1,889,000, generating earnings of $444,000 in 2014.
In 2015, we sold 9,645 acres of undeveloped land for $22,851,000, or approximately $2,369 per acre, generating approximately $16,542,000 in earnings, compared with 21,345 acres sold for $46,554,000 or approximately $2,181 per acre, generating earnings of $29,895,000 in 2014.
Commercial and income producing properties revenues include revenues from sale of multifamily properties which we develop as a merchant builder and operate until sold, from hotel room sales and other guest services, rental revenues from our operating multifamily properties and reimbursement for costs paid to subcontractors plus development and construction fees from certain multifamily projects. In 2015, revenues include $42,880,000 from the sale of Midtown Cedar Hill, a 354-unit multifamily property we developed near Dallas and $41,000,000 in 2013 from the sale of Promesa, a 289-unit multifamily property we developed in Austin. Commercial and income producing properties revenue include $6,238,000 in construction revenues associated with one multifamily fixed fee contract as general contractor which was substantially completed at year-end 2015, compared with $12,282,000 in 2014. The decrease in construction revenues in 2015 is primarily due to the completion of the Eleven project in second quarter 2014. In 2015, rental revenues from our multifamily operating properties were $8,380,000 compared with $1,550,000 in 2014, primarily due to the substantial completion of the Eleven multifamily project at the end of second quarter 2014 and acquiring our partner's interest in the multifamily venture in third quarter 2014.
On January 28, 2016, we announced that our multifamily business is non-core. As a result, we intend to opportunistically exit our multifamily portfolio and will no longer allocate capital to new communities in this business.
On February 4, 2016, we entered into a Purchase and Sale Agreement for the sale of the Radisson Hotel & Suites in Austin for $130,000,000. This transaction is subject to normal closing conditions and is expected to close in second quarter 2016.
Other revenues primarily result from sale of stream and impervious cover credits to home builders.

36


Units sold consist of:
 
For the Year
 
2015
 
2014
 
2013
Owned and consolidated ventures:
 
 
 
 
 
Residential lots sold
972

 
1,999

 
1,469

Average price per lot sold
$
76,594

 
$
55,597

 
$
58,101

Commercial acres sold
31

 
21

 
99

Average price per acre sold
$
182,184

 
$
89,681

 
$
175,972

Undeveloped acres sold
9,645

 
21,345

 
6,703

Average price per acre sold
$
2,369

 
$
2,181

 
$
3,395

Ventures accounted for using the equity method:
 
 
 
 
Residential lots sold
500

 
344

 
414

Average price per lot sold
$
78,288

 
$
72,906

 
$
58,872

Commercial acres sold
32

 
11

 
72

Average price per acre sold
$
309,224

 
$
589,574

 
$
226,206

Undeveloped acres sold
4,217

 
792

 
108

Average price per acre sold
$
2,129

 
$
2,391

 
$
2,737

In 2015, cost of sales includes $7,781,000 related to multifamily construction contracts we incurred as general contractor and paid to subcontractors associated with our development of a multifamily venture property near Denver compared to $17,393,000 in 2014, associated with two multifamily venture properties, of which one was completed in May 2014 and the other was about 80 percent complete at year-end 2014. Included in multifamily construction contract costs are charges of $1,531,000 in 2015 reflecting estimated cost increases associated with our fixed fee contracts as general contractor for these two multifamily venture properties compared to $5,107,000 in 2014. Cost of sales in 2015 and 2013 includes $33,375,000 and $29,707,000 in carrying value related to the two multifamily properties we developed as a merchant builder and sold.
In addition, cost of sales includes non-cash impairment charges of $1,044,000 in 2015, $399,000 in 2014 and $1,790,000 in 2013. The 2015 non-cash impairment charges were associated with a residential development with golf course and country club property near Fort Worth which was sold in April 2015, one project near Atlanta where the remaining lots were sold in August 2015 and one entitled project in Atlanta.
Operating expenses consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Employee compensation and benefits
$
8,989

 
$
10,327

 
$
8,073

Property taxes
9,031

 
6,919

 
7,188

Professional services
5,749

 
5,749

 
4,206

Depreciation and amortization
7,605

 
3,741

 
3,117

Other
9,128

 
7,385

 
9,368

 
$
40,502

 
$
34,121

 
$
31,952

The increase in operating expenses for 2015 is principally related to increase in depreciation and amortization and property taxes associated with the Eleven multifamily project which was completed in second quarter 2014 and the Midtown Cedar Hill multifamily project which was substantially completed in second quarter 2015. In third quarter 2014, we acquired full ownership of the Eleven multifamily project in Austin in which we previously held a 25 percent equity interest.
Interest income principally represents earnings from a loan secured by a mixed-use real estate community in Houston that was paid in full in first quarter 2015 and interest income received on reimbursements from utility and improvement districts.
In 2015, gain on sale of assets includes a gain of $1,160,000 associated with the reduction of a surety bond in connection with the Cibolo Canyons Special Improvement District (CCSID) bond offering in 2014 and $425,000 of excess hotel occupancy and sales and use tax pledged revenues from CCSID after their payments to the debt service fund. The surety bond has a balance of $7,850,000 at year-end 2015. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to San Antonio Real Estate (SARE) owner of the Resort, which obligation is scheduled to be retired in full by 2020.
In 2014, gain on sale of assets principally includes a $10,476,000 gain associated with a non-monetary exchange of leasehold timber rights on approximately 10,300 acres for 5,400 acres of undeveloped land with a partner in a consolidated

37


venture, a gain of $7,610,000 related to acquiring our partner's interest in the Eleven multifamily venture, a gain of $6,577,000 related to bond proceeds received from Cibolo Canyons Special Improvement District (CCSID) at our Cibolo Canyons project near San Antonio, and $1,318,000 gain associated with the sale of a land purchase option contract.
Increase in equity earnings from our unconsolidated ventures in 2015 compared with 2014 is primarily due to increased lot sales activity associated with two projects in Houston and increased undeveloped land sales from a venture in Atlanta.
In 2014, the decrease in net income attributable to noncontrolling interests, compared with 2013, is principally due to the acquisition of our partner's noncontrolling interest in the Lantana ventures for $7,971,000 in 2014.
We underwrite real estate development projects based on a variety of assumptions incorporated into our development plans, including the timing and pricing of sales and leasing and costs to complete development. Our development plans are periodically reviewed in comparison to our return projections and expectations, and we may revise our plans as business conditions warrant. If as a result of changes to our development plans the anticipated future net cash flows are reduced such that our basis in a project is not fully recoverable, we may be required to recognize a non-cash impairment charge for such project. See Item 1. Business for information about our net investment in owned and consolidated real estate by geographic location at year-end 2015.
As of year-end 2015, multifamily properties under various stages of development are as follows:
Multifamily Sites (a)
Project
 
Market
 
Ownership Interest
 
Acquisition of Property
 
Project Cost Incurred to Date
 
 
 
 
 
 
($ in thousands)
Downtown Edge
 
Austin
 
100
%
 
$
11,558

 
$
1,148

West Austin
 
Austin
 
100
%
 
$
8,470

 
$
627

Under Construction
Project
 
Market
 
Ownership Interest (b)
 
Estimated Project Cost (c)
 
Project Cost Incurred to Date
 
Planned
Number of Units
 
Planned
Rentable Square Feet
 
Estimated Completion Date
 
Estimated Stabilization Date (d)
 
 
 
 
 
 
($ in thousands)
 
 
 
 
 
 
 
 
Dillon
 
Charlotte
 
100
%
 
$
81,600

 
$
19,987

 
379
 
297,780

 
1Q 2018
 
1Q 2019
Music Row
 
Nashville
 
100
%
 
$
49,000

 
$
9,947

 
230
 
172,050

 
4Q 2017
 
3Q 2018
360°
 
Denver
 
20
%
 
$
56,757

 
$
56,218

 
304
 
248,684

 
1Q 2016
 
2Q 2016
Acklen
 
Nashville
 
30
%
 
$
58,100

 
$
57,302

 
320
 
249,453

 
1Q 2016
 
3Q 2016
HiLine
 
Denver
 
25
%
 
$
71,360

 
$
49,153

 
385
 
358,683

 
4Q 2016
 
2Q 2017
Elan 99 (e)
 
Houston
 
90
%
 
$
53,250

 
$
32,592

 
360
 
365,160

 
3Q 2016
 
2Q 2017
Complete
Project
 
Market
 
Ownership Interest
 
Project Cost Incurred to Date
 
Project Cost per Sq Ft
 
Number of Units
 
Rentable Square Feet
 
Completion Date
 
Stabilization Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Eleven (f)
 
Austin
 
100
%
 
$
53,958

 
$
271

 
257
 
203,757

 
2Q 2014
 
3Q 2014

  _____________________
(a)
Acquired development sites for future construction.
(b) 
We may develop and own these projects directly or through ventures.
(c) 
Estimated project costs represent the estimated costs of the project through stabilization. Final costs may differ from these estimates. The projected stabilization dates are also estimates and are subject to change as the project proceeds through the development and marketing process.
(d) 
Estimated stabilization represents the quarter within which we estimate the project will achieve 90% occupancy.
(e) 
Our venture partner is the developer of this project.
(f) 
In 2014, we acquired full ownership of the Eleven venture, in which we previously held a 25 percent interest, for $21,500,000.


38


Oil and Gas
Our oil and gas segment is focused on maximizing the value from our owned oil and gas mineral interests through promoting exploration, development and production activities by increasing acreage leased, lease rates, and royalty interests.
We lease portions of our 590,000 owned net mineral acres located principally in Texas, Louisiana, Georgia and Alabama to other oil and gas companies in return for a lease bonus, delay rentals and a royalty interest. At year-end 2015, we have about 13,000 net acres under lease to others with expiration dates ranging from 2016 to 2018, and about 42,000 net acres leased to others that are held by production related to our owned mineral interests and 533 gross productive wells operated by others on our owned mineral acres.
In addition, we are focused on exiting our non-core working interest oil and gas assets, principally in the Bakken/Three Forks of North Dakota and Lansing - Kansas City formation of Nebraska and Kansas. We will only allocate capital to these non-core assets going forward to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.
As of year-end 2015, our leasehold interests include 228,000 net mineral acres leased from others principally located in Nebraska and Kansas primarily targeting the Lansing – Kansas City formation, in Oklahoma targeting various formations in the Anadarko Basin, and in North Dakota primarily targeting the Bakken/Three Forks formations. Our leasehold interests include 9,000 net mineral acres in the Bakken/Three Forks formations. We have 43,000 net acres of leasehold interests held by production and 369 gross oil and gas wells with working interest ownership, of which 126 are operated by us.
On March 1, 2016, we sold our remaining Kansas and Nebraska oil and gas properties for $21,000,000, with a $2,000,000 contingency payment if the WTI oil price exceeds $60 Bbl for 60 consecutive trading days within one year following closing.
A summary of our oil and gas results follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Revenues
$
52,939

 
$
84,300

 
$
72,313

Cost of oil and gas producing activities
(224,400
)
 
(98,371
)
 
(42,067
)
Operating expenses
(12,504
)
 
(17,727
)
 
(13,312
)
 
(183,965
)
 
(31,798
)
 
16,934

Gain (loss) on sale of assets
(706
)
 
8,526

 
1,333

Equity in earnings of unconsolidated ventures
275

 
586

 
592

Segment earnings (loss)
$
(184,396
)
 
$
(22,686
)
 
$
18,859

Oil and gas segment earnings decreased in 2015 principally due to non-cash impairment charges of $107,140,000 for proved oil and gas properties and $57,691,000 for unproved leasehold interests driven by significantly lower realized oil prices compared with 2014.
Revenues consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Oil production (a)
$
46,428

 
$
75,075

 
$
62,379

Gas production
5,125

 
7,844

 
6,657

Other (principally lease bonus and delay rentals)
1,386

 
1,381

 
3,277

 
$
52,939

 
$
84,300

 
$
72,313

 _____________________
(a) 
Oil production includes revenues from oil, condensate and natural gas liquids (NGLs). In 2015, 2014 and 2013, NGLs accounted for $1,548,000, $2,518,000 and $1,639,000 of oil production revenues.
In 2015, oil and gas production revenues decreased principally as a result of lower realized oil and gas prices despite an increase in oil and gas production volumes as compared with 2014. The decline in oil prices negatively impacted revenues by $46,983,000 as compared with the previous year. This decline was partially offset by an $18,336,000 increase in revenues as a result of higher oil production volumes. The decline in gas prices negatively impacted revenues by $3,166,000, partially offset by a $447,000 increase in revenues as a result of increased gas production volumes compared with the previous year.
In 2014, oil and gas production revenues increased principally as a result of higher production volumes when compared with 2013. Increased oil production volume contributed $20,862,000, partially offset by decreased oil prices which negatively

39


impacted revenues by $8,166,000. Decreased gas production volume negatively impacted revenues by $190,000, offset by higher gas prices increasing revenues by $1,377,000 as compared with 2013.
In 2015, other revenues principally represents $996,000 in lease bonuses received from leasing approximately 3,300 net mineral owned acres in Texas and Louisiana to third parties for an average of $300 per acre compared with $1,244,000 in lease bonus payments in 2014 from leasing approximately 3,900 owned mineral acres for an average of $320 per acre and $2,486,000 in lease bonus payments in 2013 from leasing approximately 9,200 owned mineral acres for an average of about $270 per acre.
Oil and gas produced and average unit prices related to our working and royalty interests follows:
 
For the Year
 
2015
 
2014
 
2013
Consolidated entities:
 
 
 
 
 
Oil production (barrels)
1,046,400

 
869,700

 
648,000

Average oil price per barrel
$
42.89

 
$
83.43

 
$
93.74

NGL production (barrels)
112,100

 
61,400

 
49,700

Average NGL price per barrel
$
13.81

 
$
41.02

 
$
32.92

Total oil production (barrels), including NGLs
1,158,500

 
931,100

 
697,700

Average total oil price per barrel, including NGLs
$
40.08

 
$
80.63

 
$
89.40

Gas production (millions of cubic feet)
1,966.5

 
1,860.6

 
1,912.0

Average price per thousand cubic feet
$
2.61

 
$
4.22

 
$
3.48

Our share of ventures accounted for using the equity method:
 
 
 
 
 
Gas production (millions of cubic feet)
168.3

 
199.6

 
246.5

Average price per thousand cubic feet
$
2.54

 
$
3.94

 
$
3.25

Total consolidated and our share of equity method ventures:
 
 
 
 
 
Oil production (barrels)
1,046,400

 
869,700

 
648,000

Average oil price per barrel
$
42.89

 
$
83.43

 
$
93.74

NGL production (barrels)
112,100

 
61,400

 
49,700

Average NGL price per barrel
$
13.81

 
$
41.02

 
$
32.92

Total oil production (barrels), including NGLs
1,158,500

 
931,100

 
697,700

Average total oil price per barrel, including NGLs
$
40.08

 
$
80.63

 
$
89.40

Gas production (millions of cubic feet)
2,134.8

 
2,060.2

 
2,158.5

Average price per thousand cubic feet
$
2.60

 
$
4.19

 
$
3.46

Total BOE (barrel of oil equivalent)(a)
1,514,300

 
1,274,500

 
1,057,500

Average price per barrel of oil equivalent
$
34.33

 
$
65.68

 
$
66.04

  _____________________
(a) 
Gas is converted to barrels of oil equivalent (BOE) using six Mcf to one barrel of oil.
At year-end 2015, there were 903 productive gross wells of which 534 were operated by others on our owned mineral acres and 369 wells on our leased mineral acres, of which 126 were operated by us. At year-end 2014, there were 944 productive gross wells of which 551 were operated by others on our owned mineral acres and 393 wells on our leased mineral acres, of which 153 were operated by us. At year-end 2013, there were 1,011 productive gross wells of which 547 were operated by others on our owned mineral acres and 464 wells on our leased mineral acres, of which 182 were operated by us.
Cost of oil and gas producing activities consists of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Depletion and amortization
$
27,741

 
$
28,442

 
$
18,417

Exploration costs
10,594

 
16,648

 
10,486

Production costs
19,820

 
19,727

 
12,477

Non-cash impairment of proved oil and gas properties and unproved leasehold interests
164,831

 
32,665

 
473

Other
1,414

 
889

 
214

 
$
224,400

 
$
98,371

 
$
42,067

In 2015 and 2014, cost of oil and gas producing activities increased compared with 2013 principally due to non-cash impairments, and higher exploration, production and depletion expenses. Production costs principally represent lease operating

40


expenses associated with producing working interest wells and our share of production severance taxes related to both our royalty and working interests. Depletion and amortization represent non-cash costs of producing oil and gas associated with our working interests and are computed based on the units of production method.
All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. In 2015, we recorded non-cash impairment charges of $107,140,000 for proved oil and gas properties and $57,691,000 for unproved leasehold interests compared with $15,535,000 for proved oil and gas properties and $17,130,000 for unproved leasehold interests in 2014. We may incur additional near-term impairments due to continuation of declining oil and gas prices, changes in production rates, future development costs and levels of proved reserves.
Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs. Dry hole costs were $9,949,000 in 2015, which includes a $9,674,000 charge primarily associated with an exploratory well in Oklahoma, $12,398,000 in 2014, which includes $5,151,000 principally in Kansas and Nebraska, $4,040,000 in east Texas and $3,207,000 in Oklahoma compared with dry hole costs of $5,837,000 in 2013. In addition, 2015 exploration costs included write-off of $917,000 of pre-drilling costs associated with oil and gas properties in Oklahoma.
Operating expenses consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Employee compensation and benefits
$
6,315

 
$
10,082

 
$
8,168

Professional and consulting services
1,723

 
3,156

 
1,557

Depreciation
1,033

 
1,001

 
1,135

Property taxes
304

 
399

 
436

Other
3,129

 
3,089

 
2,016

 
$
12,504

 
$
17,727

 
$
13,312

Operating expenses decreased in 2015 compared with 2014 primarily due to significantly reducing our workforce as a result of classifying oil and gas working interest assets as non-core and our announced plan to exit these assets. The reduction in operating expenses in 2015 was partially offset by $2,047,000 of employee severance and retention bonuses and $1,750,000 for a lease termination charge associated with closing our office in Fort Worth.
In 2015, we recorded a net loss of $706,000 on the sale of 109,000 net mineral acres leased from others and the disposition of 39 gross (7 net) producing oil and gas wells in Nebraska, Texas, Colorado, North Dakota and Oklahoma for total sales proceeds of $17,800,000. In 2014, we recorded gains of $8,526,000 related to the sale of 650 net mineral acres in North Dakota and the sale of 124 gross (18 net) producing oil and gas wells primarily in Oklahoma.
Equity in earnings of unconsolidated ventures includes our share of royalty revenue from producing wells in the Barnett Shale gas formation.

Other Natural Resources
Our other natural resources segment manages our timber holdings, recreational leases and water resource initiatives. We have 89,000 acres of non-core timberland and undeveloped land we own directly or through ventures, primarily in Georgia and Texas. Other natural resources segment revenues are principally derived from sales of wood fiber from our land and leases for recreational uses. We have water interests in 1.5 million acres, including a 45 percent nonparticipating royalty interest in groundwater produced or withdrawn for commercial purposes or sold from 1.4 million acres in Texas, Louisiana, Georgia and Alabama, and 20,000 acres of groundwater leases in central Texas.

41


A summary of our other natural resources results follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Revenues
$
6,652

 
$
9,362

 
$
10,721

Cost of other natural resources
(3,081
)
 
(3,006
)
 
(2,033
)
Operating expenses
(4,330
)
 
(4,419
)
 
(6,065
)
 
(759
)
 
1,937

 
2,623

Gain on sale and partial termination of timber lease
—

 
3,531

 
3,828

Equity in earnings of unconsolidated ventures
151

 
31

 
56

Segment earnings (loss)
$
(608
)
 
$
5,499

 
$
6,507

Revenues consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Fiber
$
5,011

 
$
7,050

 
$
9,584

Water
489

 
1,100

 
—

Recreational leases and other
1,152

 
1,212

 
1,137

 
$
6,652

 
$
9,362

 
$
10,721

Fiber sold consists of:
 
For the Year
 
2015
 
2014
 
2013
Pulpwood tons sold
149,700

 
209,900

 
375,200

Average pulpwood price per ton
$
9.71

 
$
10.62

 
$
9.26

Sawtimber tons sold
77,000

 
120,000

 
234,300

Average sawtimber price per ton
$
20.86

 
$
22.47

 
$
22.31

Total tons sold
226,700

 
329,900

 
609,500

Average stumpage price per ton (a)
$
13.50

 
$
14.93

 
$
14.28

 _____________________
(a) 
Average stumpage price per ton is based on gross revenues less cut and haul costs.
Water revenues are associated with a groundwater reservation agreement with Hays County, Texas, which commenced in 2013 and was terminated in 2015.
Information about our recreational leases follows:
 
For the Year
 
2015
 
2014
 
2013
Average recreational acres leased
98,300

 
110,500

 
120,400

Average price per leased acre
$
9.17

 
$
9.13

 
$
9.08


Cost of other natural resources principally includes non-cash cost of timber cut and sold and delay rental payments paid to others related to groundwater leases in central Texas.
Operating expenses consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Employee compensation and benefits
$
2,110

 
$
2,127

 
$
2,280

Professional and consulting services
1,433

 
1,587

 
2,813

Other
787

 
705

 
972

 
$
4,330

 
$
4,419

 
$
6,065


42


Operating expenses associated with our water resources initiatives were $2,162,000 in 2015, $2,437,000 in 2014 and $3,588,000 in 2013.
Gain on sale and partial termination of timber lease in 2014 includes a $3,366,000 gain associated with partial terminations of a timber lease related to the remaining 2,700 acres of undeveloped land sold from a consolidated venture near Atlanta, Georgia.
Items Not Allocated to Segments
Unallocated items represent income and expenses managed on a company-wide basis and include general and administrative expenses, share-based and long-term incentive compensation, gain on sale of strategic timberland, interest expense and other corporate non-operating income and expense. General and administrative expenses principally consist of accounting and finance, tax, legal, human resources, internal audit, information technology and our board of directors. These functions support all of our business segments and are not allocated.
General and administrative expense
General and administrative expenses consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Employee compensation and benefits
$
11,729

 
$
8,948

 
$
8,783

Professional and consulting services
6,056

 
4,647

 
4,117

Facility costs
889

 
928

 
838

Insurance costs
682

 
1,115

 
898

Depreciation and amortization
595

 
638

 
833

Other
4,851

 
4,953

 
5,128

 
$
24,802

 
$
21,229

 
$
20,597

In 2015, employee compensation and benefits includes $3,314,000 of severance charges related to the departure of our former CEO and CFO under employment and separation agreements.
Share-based compensation expense
Our share-based compensation expense principally fluctuates due to a portion of our awards being cash-settled and as a result are affected by changes in the market price of our common stock.
Long-term incentive compensation expense
In 2015, we granted $587,000 of long-term incentive compensation in the form of deferred cash compensation. Deferred cash will be paid out after the earlier of three years or the employee's retirement eligibility date, and the expense is recognized ratably over the vesting period.
Interest expense
The increase in interest expense in 2015 and 2014 is primarily due to higher average borrowing rates and higher average levels of debt outstanding.
Income taxes
Our effective tax rate was 18 percent in 2015, 34 percent in 2014 and 17 percent in 2013. Our 2015 effective tax rate includes a 54 percent detriment from a valuation allowance on our deferred tax asset. Excluding the impact of valuation allowance our effective tax rate was a 36 percent benefit in 2015. Our 2013 effective tax rate includes a 15 percent benefit from the recognition of a previously reserved tax position.
Our 2015, 2014 and 2013 effective tax rates include the effect of state income taxes, nondeductible items and benefits from percentage depletion and noncontrolling interests.
At year-end 2015 and 2014, we have provided a valuation allowance for our deferred tax asset of $97,068,000 and $384,000 respectively for the portion of the deferred tax asset that we have determined is more likely than not to be unrealizable.
In determining our valuation allowance, we assessed available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax asset. A significant piece of objective evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2015, principally

43


driven by impairments of oil and gas properties. Such evidence limits our ability to consider other subjective evidence, such as our projected future taxable income.
The amount of deferred tax asset considered realizable could be adjusted if negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence, such as our projected future taxable income.

Capital Resources and Liquidity
Sources and Uses of Cash
We operate in cyclical industries and our cash flows fluctuate accordingly. Our principal sources of cash are proceeds from the sale of real estate and timber, the cash flow from oil and gas and income producing properties, borrowings and reimbursements from utility and improvement districts. Our principal cash requirements are for the acquisition and development of real estate and investment in oil and gas leasing and production activities, either directly or indirectly through ventures, taxes, interest and compensation. Operating cash flows are affected by the timing of the payment of real estate development expenditures and the collection of proceeds from the eventual sale of the real estate, the timing of which can vary substantially depending on many factors including the size of the project, state and local permitting requirements and availability of utilities and by the timing of oil and gas leasing and production activities. Working capital varies based on a variety of factors, including the timing of sales of real estate and timber, oil and gas leasing and production activities, collection of receivables, reimbursement from utility and improvement districts and the payment of payables and expenses.
We regularly evaluate alternatives for managing our capital structure and liquidity profile in consideration of expected cash flows, growth and operating capital requirements and capital market conditions. We may, at any time, be considering or be in discussions with respect to the purchase or sale of our common stock, debt securities, convertible securities or a combination thereof.
Cash Flows from Operating Activities
Cash flows from our real estate acquisition and development activities, undeveloped land sales, commercial and income producing properties, timber sales, income from oil and gas properties, recreational leases and reimbursements from utility and improvement districts are classified as operating cash flows.
In 2015, net cash provided by operating activities was $35,126,000. The decrease in net cash provided by operating activities year over year is primarily the result of lower residential lot sales activity, decrease in reimbursement from utilities and improvement districts and decrease in undeveloped land sales. In addition, oil and gas operating cash flows were negatively impacted as a result of 48 percent decline in realized oil and gas prices on a barrel of oil equivalent basis. However, the sale of Midtown Cedar Hill for $42,880,000 in fourth quarter 2015 generated positive operating cash flow of $42,640,000. These cash flows were partially offset by real estate development and acquisition expenditures of $107,998,000.
In 2014, net cash provided by operating activities was $107,082,000 principally due to $66,047,000 of reimbursements from utilities and improvement districts. In addition, increased residential lot sales and undeveloped land sales activity contributed to our net cash from operations, which are partially offset by $114,694,000 of real estate development and acquisition expenditures exceeding $84,665,000 of real estate cost of sales.
In 2013, net cash provided by operations was $88,777,000 primarily due to higher earnings and the sale of Promesa, a 289-unit multifamily property we developed and sold for $41,000,000, of which $10,881,000 is included in pre-tax income and $29,707,000 of carrying value is included in real estate cost on sales on the statement of cash flows. These cash flows were partially offset by real estate development and acquisition expenditures of $106,609,000.
Cash Flows from Investing Activities
Capital contributions to and capital distributions from unconsolidated ventures, costs incurred to acquire, develop and construct multifamily projects that will be held as commercial properties upon stabilization as investment property, business acquisitions and investment in oil and gas properties and equipment are classified as investing activities. In addition, proceeds from the sale of property and equipment, software costs and expenditures related to reforestation activities are also classified as investing activities.
In 2015, net cash used for investing activities was $60,328,000 principally due to our investment of $49,717,000 in oil and gas properties associated with previously committed capital investments related to exploration and production operations and a net investment in unconsolidated ventures of $14,181,000. In addition, we invested $14,690,000 in property and equipment, software and reforestation, of which $5,953,000 is related to capital expenditures for our 413 guest room hotel in Austin, which is under contract to be sold for $130,000,000 and expected to close in second quarter 2016. These are partially offset by proceeds from sale of assets of $18,260,000 principally related to sale of certain oil and gas properties.

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In 2014, net cash used for investing activities was $129,731,000 principally due to our investment of $101,145,000 in oil and gas properties and equipment associated with our exploration and production operations and purchase of our partner's interest in a 257-unit multifamily property in Austin for $20,155,000, net of cash. In addition, we invested $16,398,000 in property and equipment, software and reforestation, of which $8,780,000 is related to capital expenditures on our 413 guest room hotel in Austin and $4,981,000 is related to water production well development, and a net investment in unconsolidated ventures of $12,895,000. These are partially offset by proceeds from sale of assets of $21,962,000 principally related to sale of certain oil and gas properties in North Dakota and Oklahoma.
In 2013, net cash used for investing activities was $103,927,000 principally due to our investment of $96,069,000 in oil and gas properties and equipment associated with our exploration and production operations. In addition, we invested $11,828,000 in property and equipment, software and reforestation of which $7,245,000 is related to capital expenditures on our 413 guest room hotel in Austin.
Cash Flows from Financing Activities
In 2015, net cash used for financing activities was $48,483,000 principally due to our payment in full of a $24,166,000 loan secured by Midtown Cedar Hill, which we sold in fourth quarter 2015, retirement of $19,440,000 of our 8.50% senior secured notes and $9,000,000 of payments related to amortizing notes associated with our tangible equity units.
In 2014, net cash provided by financing activities was $469,000 principally due to net proceeds of $241,947,000 from the issuance of 8.5% senior secured notes, partially offset by debt payments of $225,481,000, of which $200,000,000 is related to retirement of the term loan associated with our senior secured credit facility, $9,450,000 is related to payments of our amortizing notes associated with our tangible equity units, $2,878,000 is related to debt outstanding for our Lantana partnerships and the remaining associated with payment of other indebtedness. In addition, we purchased 1,491,187 shares of our common stock for $24,595,000.
In 2013, net cash provided by financing activities was $197,096,000 principally due to net proceeds of $144,998,000 from the issuance of 6.00% tangible equity units and net proceeds of $120,795,000 from the issuance of 3.75% convertible senior notes, partially offset by net debt repayments of $106,076,000, of which $68,000,000 is related to payoff of debt outstanding under our revolving line of credit and $18,902,000 is related to paying off a loan associated with Promesa.
Real Estate Acquisition and Development Activities
We secure entitlements and develop infrastructure, primarily for single family residential and mixed-use communities.
We categorize real estate development and acquisition expenditures as operating activities on the statement of cash flows. These development and acquisition expenditures include costs for development of residential lots and mixed-used communities and multifamily community projects that will be marketed for sale upon stabilization.
In 2015, real estate development and acquisition expenditures were $107,988,000 which includes the acquisition of five new community development sites for $29,726,000 and real estate development costs of $78,262,000.

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A summary of our real estate acquisition and development expenditures is shown below:
 
 
 
 
2015
 
2014
 
2013
 
 
 
 
(In thousands)
Community Development
 
Market
 
 
 
 
 
 
Acquisitions:
 
 
 
 
 
 
 
 
Ansley Park
 
Charlotte
 
5,339

 
—

 
—

Beckwith Crossing
 
Nashville
 
—

 
1,294

 
—

Dove Mountain
 
Tucson
 
5,861

 
—

 
—

Habersham
 
Charlotte
 
—

 
—

 
3,878

Imperial Forest
 
Houston
 
—

 
5,343

 
—

Morgan Farms
 
Nashville
 
—

 
146

 
6,841

Parkside
 
Dallas
 
—

 
—

 
2,177

River's Edge
 
Dallas
 
—

 
1,277

 
—

Vickery Park
 
Nashville
 
3,345

 
—

 
—

Walden
 
Charlotte
 
12,100

 
—

 
—

Weatherford Estates
 
Nashville
 
—

 
855

 
—

West Oaks
 
Atlanta
 
1,657

 
—

 
—

Woodtrace
 
Houston
 
1,424

 
8,622

 
—

Development:
 
 
 
 
 
 
 
 
Owned projects
 
Various
 
63,401

 
50,506

 
46,314

Consolidated venture projects
 
Various
 
10,534

 
3,905

 
19,567

 
 
 
 
 
 
 
 
 
Multifamily
 
 
 
 
 
 
 
 
Acquisitions and Development:
 
 
 
 
 
 
 
 
Pre-acquisition projects
 
Various
 
1,616

 
910

 
797

Midtown
 
Dallas
 
1,860

 
25,034

 
4,232

Acklen (a)
 
Nashville
 
—

 
(7,191
)
 
1,048

HiLine (a)
 
Denver
 
—

 
(9,372
)
 
14,272

Dillon
 
Charlotte
 
—

 
2,905

 
5,845

Music Row
 
Nashville
 
—

 
6,757

 
—

Downtown Edge
 
Austin
 
—

 
11,286

 
—

West Austin
 
Austin
 
—

 
8,456

 
—

 
 
 
 
 
 
 
 
 
Undeveloped Land/Mitigation
 
 
 
 
 
 
 
 
Acquisitions:
 
 
 
 
 
 
 
 
Crescent Hills
 
San Antonio
 
—

 
1,829

 
—

Development:
 
 
 
 
 
 
 
 
Owned projects
 
Various
 
851

 
2,132

 
1,638

Total
 
 
 
$
107,988

 
$
114,694

 
$
106,609

  _____________________
(a)
Includes reimbursements received from the ventures for land and pre-development costs.
Oil and Gas Drilling and Other Exploration and Development Activities
In 2015, we drilled or participated as a non-operator in approximately 38 gross wells (6 net). At year-end 2015, we had interests in 903 gross productive wells.
In 2015, we acquired leasehold interests principally in Nebraska, Kansas and North Dakota for $4,832,000 representing 6,000 net mineral acres which was principally carryover commitments from 2014. Also, leasehold interests of approximately 35,000 net mineral acres expired in the normal course of business in 2015, principally in Kansas and Nebraska.
In 2014, we acquired leasehold interests principally in Nebraska, Kansas, Texas, Oklahoma and North Dakota for $25,719,000 representing over 141,000 net mineral acres. Also, leasehold interests of approximately 18,000 net mineral acres expired in the normal course of business in 2014, principally in Kansas and Nebraska.
Our capital expenditures for 2015 are significantly lower compared with 2014 and are primarily related to existing well commitments in the Bakken/Three Forks formation of North Dakota. In 2015, drilling and completion activity included 32 gross Bakken/Three Forks wells generating initial production and two wells waiting on completion at year-end 2015. In addition, in 2015 we elected to participate as a non-operator in 14 new gross wells for $16,074,000 in the Bakken/Three Forks formation of North Dakota.

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Regional allocation of our capital expenditures incurred and paid for drilling and completion activity in 2015 and 2014 is shown below:
 
Drilling and Completion Expenditures
 
2015
 
2014
 
(In thousands)
Bakken and Three Forks formations of North Dakota
$
26,780

 
$
40,270

Lansing - Kansas City formation of Nebraska and Kansas
2,762

 
18,899

Other formations principally in Texas and Oklahoma
15,343

 
16,257

 
$
44,885

 
$
75,426

Accrued capital expenditures for drilling and completion costs at year-end 2015 were $7,033,000 and are included in other accrued expenses in our consolidated balance sheets. These oil and gas property additions will be reflected as cash used for investing activities in the period the accrued payables are settled. Of the $44,885,000 of capital expenditures we incurred and paid in 2015 for drilling and completion activities, $39,931,000 was related to settling year-end 2014 accrued capital expenditures and payment of 2014 well commitments that were completed as of year-end 2015.
Planned capital expenditures for 2016 are expected to be significantly lower than 2015 based on our plan to exit non-core oil and gas assets and only allocate capital to preserve value and optionality for the ultimate sale as we evaluate exiting these assets.
Liquidity
Senior Credit Facility
At year-end 2015, our senior secured credit facility provides for a $300,000,000 revolving line of credit maturing May 15, 2017 (with two one-year extension options). The revolving line of credit may be prepaid at any time without penalty. The revolving line of credit includes a $100,000,000 sublimit for letters of credit, of which $15,899,000 is outstanding at year-end 2015. Total borrowings under our senior secured credit facility (including the face amount of letters of credit) may not exceed a borrowing base formula.
At year-end 2015, net unused borrowing capacity under our senior secured credit facility is calculated as follows:
 
Senior
Credit Facility
 
(In thousands)
Borrowing base availability
$
300,000

Less: borrowings
—

Less: letters of credit
(15,899
)
Net unused borrowing capacity
$
284,101

Our net unused borrowing capacity during fourth quarter 2015 ranged from a high of $284,101,000 to a low of $283,949,000. Certain non-core assets support the borrowing base under our senior secured credit facility so we expect our borrowing capacity to be reduced as certain non-core assets are sold. This facility is used primarily to fund our operating cash needs, which fluctuate due to timing of residential and commercial real estate sales, undeveloped land sales, oil and gas leasing, exploration and production activities and mineral lease bonus payments received, timber sales, reimbursements from utility and improvement districts, payment of payables and expenses and capital expenditures.
Our debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. On September 30, 2015, we received a waiver of the consolidated tangible net worth
maintenance covenant requirement of our senior credit facility for third quarter 2015, and amended the consolidated tangible
net worth maintenance covenant requirement to $379,044,000 (subject to adjustment as set forth in the financial covenants table below). On December 30, 2015, we amended our senior secured credit facility to reduce the interest coverage ratio from 2.50:1.0 to 2.25:1.0 for the quarters ending December 31, 2015 and March 31, 2016. Thereafter, the interest coverage ratio returns to 2.50:1.0. At year-end 2015, we were in compliance with the financial covenants of these agreements.

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The following table details our compliance with the financial covenants calculated as provided in the senior secured credit facility:
Financial Covenant
Requirement
 
Year-End
2015
Interest Coverage Ratio (a)
≥ 2.25:1.0
 
2.85
Total Leverage Ratio (b)
≤ 50%
 
40.5%
Tangible Net Worth (c)
≥ $379.0 million
 
$470.2 million
  _____________________
(a) 
Calculated as EBITDA (earnings before interest, taxes, depreciation, depletion and amortization), plus non-cash compensation expense, plus other non-cash expenses, divided by interest expense excluding loan fees. This covenant is applied at the end of each quarter on a rolling four quarter basis.
(b) 
Calculated as total funded debt divided by adjusted asset value. Total funded debt includes indebtedness for borrowed funds, secured liabilities, reimbursement obligations with respect to letters of credit or similar instruments, and our pro-rata share of joint venture debt outstanding. Adjusted asset value is defined as the sum of unrestricted cash and cash equivalents, timberlands, high value timberlands, raw entitled lands, entitled land under development, minerals business, Credo asset value, special improvement district receipts (SIDR) reimbursements value and other real estate owned at book value without regard to any indebtedness and our pro rata share of joint ventures’ book value without regard to any indebtedness. This covenant is applied at the end of each quarter.
(c) 
Calculated as the amount by which consolidated total assets (excluding Credo acquisition goodwill over $50,000,000) exceeds consolidated total liabilities. At year-end 2015, the requirement is $379,044,000 computed as: $379,044,000 plus 85 percent of the aggregate net proceeds received by us from any equity offering, plus 75 percent of all positive net income, on a cumulative basis. This covenant is applied at the end of each quarter.
To make additional investments, acquisitions, or distributions, we must maintain available liquidity equal to 10 percent of the aggregate commitments in place. At year-end 2015 the minimum liquidity requirement was $30,000,000, compared with $372,975,000 in actual available liquidity based on the unused borrowing capacity under our senior secured credit facility plus unrestricted cash and cash equivalents. The failure to maintain such minimum liquidity does not constitute a default or event of default of our senior secured credit facility.
We may elect to make distributions so long as the total leverage ratio is less than 40 percent, the interest coverage ratio is greater than 3.0:1.0 and available liquidity is not less than $125,000,000. Effective December 30, 2015, the senior secured credit facility was amended to provide that we may make distributions in an aggregate amount not to exceed $50,000,000 to be funded from up to 65% of the net proceeds from sales of multifamily properties and non-core assets, such as the Radisson Hotel & Suites in Austin, and any oil and gas properties. The amendment provides us the flexibility to repurchase stock or pay a special dividend should our Board of Directors determine that we should do so, though no such decisions have been made at this time.
Discretionary investments in community development may be restricted in the event that the revenue/capital expenditure ratio is less than or equal to 1.0x. As of year-end 2015, the revenue/capital expenditure ratio was 1.8x. Revenue is defined as total gross revenues (excluding revenues attributed to certain oil and gas operations and multifamily properties), plus our pro rata share of the operating revenues from unconsolidated ventures. Capital expenditures are defined as consolidated development and acquisition expenditures (excluding investments related to certain oil and gas operations and multifamily properties), plus our pro rata share of unconsolidated ventures’ development and acquisition expenditures.
8.50% Senior Secured Notes due 2022
In May 2014, we issued $250,000,000 aggregate principal amount of 8.50% senior secured notes (Notes) due 2022 in a private placement. The Notes pay interest semiannually and mature on June 1, 2022. Net proceeds from the offering were used to retire the $200,000,000 term loan under our senior secured credit facility and pay transaction costs and expenses.
In December 2015, we purchased and retired $19,440,000 principal amount of Notes at 97% of face value. We recognized a gain of $589,000 on the early extinguishment of the retired Notes which was partially offset by a write-off of unamortized debt issuance costs of $506,000 allocated to the retired Notes. Net gain on early extinguishment of debt was $83,000 which is reported in other non-operating income on our consolidated statements of income (loss) and comprehensive income (loss).
6.00% Tangible Equity Units
In November 2013, we issued $150,000,000 aggregate principal amount of 6.00% tangible equity units (Units). The total offering was 6,000,000 Units, including an over-allotment option of 600,000 exercised by the underwriters, each with a stated amount of $25.00. Each Unit is comprised of (i) a prepaid stock purchase contract to be settled by delivery of a number of

48


shares of our common stock, par value $1.00 per share to be determined pursuant to a purchase contract agreement, and (ii) a senior amortizing note due December 15, 2016 that has an initial principal amount of $4.2522, bears interest at a rate of 4.50% per annum and has a final installment payment date of December 15, 2016. The aggregate principal amount of the senior amortizing notes was $25,619,000 at the time of issuance. The aggregate number of shares we may issue upon settlement of the stock purchase contracts will between 6,547,900 shares (the minimum settlement rate) and 7,857,500 (the maximum settlement rate). The aggregate principal outstanding at year-end 2015, net of discount, was $8,768,000.
3.75% Convertible Senior Notes due 2020
In February 2013, we issued $125,000,000 aggregate principal amount of 3.75% Convertible Senior Notes due 2020. The convertible senior notes pay interest semiannually at a rate of 3.75 percent per annum and mature on March 1, 2020. The convertible senior notes have an initial conversion rate of 40.8351 per $1,000 principal amount (equivalent to a conversion price of approximately $24.49 per share of common stock and a conversion premium of 37.5 percent based on the closing share price of $17.81 per share of our common stock on February 20, 2013). The initial conversion rate is subject to adjustment upon the occurrence of certain events. Prior to November 1, 2019, the convertible senior notes are convertible only upon certain circumstances, and thereafter are convertible at any time prior to the close of business on the second scheduled trading day prior to maturity. Upon conversion, holders will receive cash, shares of our common stock or a combination thereof at our election. The aggregate principal outstanding at year-end 2015, net of discount, was $106,762,000.
Senior Secured Construction Loan
On October 16, 2015, we obtained a senior secured construction loan in the amount of $52,000,000 from PNC Bank, National Association. Principal will be advanced from time to time to finance construction of the 379-unit multifamily project located in Charlotte, North Carolina (the Dillon project). The loan is secured by a lien on the project land and improvements to be constructed, and by a collateral assignment of present and future leases and rents. The loan bears interest at the LIBOR rate plus 2.20%, payable monthly, has an initial term of 48 months and may be extended for two additional 12-month periods following the initial term, subject to payment of extension fees and fulfillment of specified conditions. There was no outstanding balance at year-end 2015.
Contractual Obligations
At year-end 2015, contractual obligations consist of:
 
 
Payments Due or Expiring by Year
 
 
Total
 
2016
 
2017-18
 
2019-20
 
Thereafter
 
 
(In thousands)
Debt (a)
 
$
389,782

 
$
27,973

 
$
24,487

 
$
106,762

 
$
230,560

Interest payments on debt
 
149,457

 
25,961

 
49,435

 
44,665

 
29,396

Purchase obligations
 
75,192

 
75,192

 
—

 
—

 
—

Operating leases
 
7,543

 
2,696

 
4,444

 
344

 
59

Performance bond (a)
 
7,850

 
7,850

 
—

 
—

 
—

Standby letter of credit (a)
 
6,846

 
6,846

 
—

 
—

 
—

Total
 
$
636,670

 
$
146,518

 
$
78,366

 
$
151,771

 
$
260,015

  _____________________
(a) 
Items included in our balance sheet.
Interest payments on debt include interest payments related to our fixed rate debt and estimated interest payments related to our variable rate debt. Estimated interest payments on variable rate debt were calculated assuming that the outstanding balances and interest rates that existed at year-end 2015 remain constant through maturity.
Purchase obligations are defined as legally binding and enforceable agreements to purchase goods and services. Our purchase obligations include commitments of $19,396,000 for land acquisition and development primarily related to community development projects and commitments of $55,796,000 for engineering and construction contracts associated with multifamily projects. The multifamily project obligations typically are reimbursed by equity method ventures on jointly owned projects or funded by construction loan draws on wholly-owned projects.
Our operating leases are for facilities, equipment and groundwater. We lease approximately 32,000 square feet of office space in Austin as our corporate headquarters. At year-end 2015, the remaining contractual obligation for our Austin office is $4,212,000. We also lease office space in several other locations in support of our business operations including approximately 21,000 square feet in Denver. The total remaining contractual obligations for these leases is $2,269,000. Also included are groundwater leases for about 20,000 acres in central Texas with remaining contractual obligations of $1,009,000.

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The performance bond and standby letter of credit were provided in support of a bond issuance by CCSID. Please read Cibolo Canyons — San Antonio, Texas for additional information.
Off-Balance Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements to facilitate our operating activities. At year-end 2015, our off-balance sheet unfunded arrangements, excluding contractual interest payments, purchase obligations, operating lease obligations and venture contributions included in the table of contractual obligations, consist of:
 
Payments Due or Expiring by Year
 
Total
 
2016
 
2017-18
 
2019-20
 
Thereafter
 
(In thousands)
Performance bonds
$
13,354

 
$
13,327

 
$
27

 
$
—

 
$
—

Standby letters of credit
9,053

 
6,986

 
2,067

 
—

 
—

Recourse obligations
973

 
597

 
6

 
240

 
130

Total
$
23,380

 
$
20,910

 
$
2,100

 
$
240

 
$
130

Performance bonds, letters of credit and recourse obligations provided on behalf of certain ventures would be drawn on due to failure to satisfy construction obligations as general contractor or for failure to timely deliver streets and utilities in accordance with local codes and ordinances.
In 2014, FMF Littleton LLC, an equity method venture in which we own a 25 percent interest, obtained a senior secured construction loan in the amount of $46,384,000 to develop a 385-unit multifamily project located in Littleton, Colorado. The outstanding balance was $22,499,000 at year-end 2015. We provided the lender with a guaranty of completion of the improvements; a guaranty for repayment of 25 percent of the principal balance and unpaid accrued interest; and a standard nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to ten percent upon achievement of certain conditions.
In 2014, CREA FMF Nashville LLC, an equity method venture in which we own a 30 percent interest, obtained a senior secured construction loan in the amount of $51,950,000 to develop a 320-unit multifamily project located in Nashville, Tennessee. The outstanding balance at year-end 2015 was $51,028,000. We provided the lender with a guaranty of completion of the improvements; a guaranty for repayment of 25 percent of the principal balance and unpaid accrued interest; and a standard nonrecourse carve-out guaranty. The principal guaranty will reduce from 25 percent of principal to zero percent
upon achievement of certain conditions.
In 2012, FMF Peakview LLC, an equity method venture in which we own a 20 percent interest, obtained a senior secured construction loan in the amount of $31,550,000 to develop a 304-unit multifamily property in Denver, of which $30,524,000 was outstanding at year-end 2015. We have a construction completion guaranty, a repayment guaranty for 25 percent of the principal and unpaid accrued interest, and a standard non-recourse carve-out guaranty.
At year-end 2015, we participate in two equity method partnerships that are variable interest entities. The partnerships have total assets of $62,187,000 and total liabilities of $55,989,000, which includes $2,269,000 of borrowings classified as current maturities. These partnerships are managed by third parties who intend to extend or refinance these borrowings; however, there is no assurance that this can be done. Although these borrowings are guaranteed by third parties, we may under certain circumstances elect or be required to provide additional equity to these partnerships. We do not believe that the ultimate resolution of these matters will have a significant effect on our earnings or financial position. Our investment in these partnerships is $5,322,000 at year-end 2015.
Cibolo Canyons — San Antonio, Texas
Cibolo Canyons consists of the JW Marriott® San Antonio Hill Country Resort & Spa development owned by third parties and a mixed-use development we own. We have about $58,750,000 invested in Cibolo Canyons at year-end 2015, all of which is related to the mixed-use development.
Resort Hotel, Spa and Golf Development
In 2007, we entered into agreements to facilitate third-party construction and ownership of the JW Marriott® San Antonio Hill Country Resort & Spa, which includes a 1,002 room destination resort and two PGA Tour® Tournament Players Club® (TPC) golf courses. Under these agreements, we agreed to transfer to third-party owners 700 acres of undeveloped land, to provide $30,000,000 cash and to provide $12,700,000 of other consideration principally consisting of golf course construction materials, all of which has been provided.
In exchange for our commitment to the resort, the third-party owners assigned to us certain rights under an agreement between the third-party owners and CCSID. This agreement includes the right to receive from CCSID nine percent of hotel occupancy revenues and 1.5 percent of other resort sales revenues collected as taxes by the CCSID through 2034. The amount

50


we receive will be net of annual ad valorem tax reimbursements by CCSID to the third-party owners of the resort through 2020. In addition, these payments will be net of debt service on bonds issued by CCSID collateralized by hotel occupancy tax and other resort sales tax through 2034.
The amounts we collect under this agreement are dependent on several factors including the amount of revenues generated by and ad valorem taxes imposed on the Resort and the amount of any applicable debt service incurred by CCSID.
In 2014, we received $50,550,000 from CCSID under 2007 Economic Development Agreements (EDA) related to development of the Resort at our Cibolo Canyons project near San Antonio, of which $46,500,000 was related to CCSID's issuance of $48,900,000 HOT and Sales and Use Tax Revenue Bonds. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied on the Resort by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with SARE, owner of the Resort, to assign SARE’s senior rights under the EDA to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable to SARE. The surety bond has a balance of $7,850,000 at year-end 2015. The surety bond will decrease as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. All future receipts are expected to be recognized as gains in the period collected.
Mixed-Use Development
The mixed-use development we own consists of 2,100 acres planned to include 1,769 residential lots and 150 commercial acres designated for multifamily and retail uses, of which 997 lots and 130 commercial acres have been sold through year-end 2015.
In 2007, we entered into an agreement with CCSID providing for reimbursement of certain infrastructure costs related to the mixed-use development. Reimbursements are subject to review and approval by CCSID and unreimbursed amounts accrue interest at 9.75 percent. CCSID’s funding for reimbursements is principally derived from its ad valorem tax collections and bond proceeds collateralized by ad valorem taxes, less debt service on these bonds and annual administrative and public service expenses.
Because the amount of each reimbursement is dependent on several factors, including timing of CCSID approval and CCSID having an adequate tax base to generate funds that can be used to reimburse us, there is uncertainty as to the amount and timing of reimbursements under this agreement. We expect to recover our investment from lot and tract sales and reimbursement of approved infrastructure costs from CCSID. We have not recognized income from interest due, but not collected. As these uncertainties are clarified, we will modify our accounting accordingly.
Through year-end 2015, we have submitted and received reimbursement approval for $54,376,000 of infrastructure costs, of which we have received reimbursements totaling $34,703,000, of which $1,150,000 was received in 2015, $9,883,000 was received in 2014, $600,000 was received in 2013, and all receipts were accounted for as a reduction of our investment in the mixed-use development. At year-end 2015, we have $19,673,000 in pending reimbursements, excluding interest. At year-end 2015, we have $58,750,000 invested in the mixed-use development.
Accounting Policies
Critical Accounting Estimates
In preparing our financial statements, we follow generally accepted accounting principles, which in many cases require us to make assumptions, estimates, and judgments that affect the amounts reported. Our significant accounting policies are included in Note 1 to the Consolidated Financial Statements. Many of these principles are relatively straightforward. There are, however, a few accounting policies that are critical because they are important in determining our financial condition and results of operations and involve significant assumptions, estimates and judgments that are difficult to determine. We must make these assumptions, estimates and judgments currently about matters that are inherently uncertain, such as future economic conditions, operating results and valuations, as well as our intentions. As the difficulty increases, the level of precision decreases, meaning actual results can, and probably will, differ from those currently estimated. We base our assumptions, estimates and judgments on a combination of historical experiences and other factors that we believe are reasonable. We have reviewed the selection and disclosure of these critical accounting estimates with our Audit Committee.
•
Investment in Real Estate and Cost of Real Estate Sales — In allocating costs to real estate owned and real estate sold, we must estimate current and future real estate values. Our estimates of future real estate values sometimes must extend over periods 15 to 20 years from today and are dependent on numerous assumptions including our intentions and future market and economic conditions. In addition, when we sell real estate from projects that are not finished, we must estimate future development costs through completion. Differences between our estimates and actual results will affect future carrying values and operating results.

51


•
Impairment of Real Estate Long-Lived Assets — Measuring real assets for impairment requires estimating the future undiscounted cash flows based on our intentions as to holding periods, and the residual value of assets under review, primarily undeveloped land. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the real estate long-lived assets to fair value. Depending on the asset under review, we use varying methods to determine fair value, such as discounting expected future cash flows, determining resale values by market, or applying a capitalization rate to net operating income using prevailing rates in a given market. Changes in economic conditions, demand for real estate, and the projected net operating income for a specific property will inevitably change our estimates.
•
Accrued Oil and Gas Revenue — We recognize revenue as oil and gas is produced and sold. There are a significant amount of oil and gas properties which we do not operate and, therefore, revenue is typically recorded in the month of production based on an estimate of our share of volumes produced and prices realized. We obtain the most current available production data from the operators and price indices for each well to estimate the accrual of revenue. Obtaining production data on a timely basis for some wells is not feasible; therefore we utilize past production receipts and estimated sales price information to estimate accrual of working interest revenue on all other non-operated wells each month. Revisions to such estimates are recorded as actual results become known.
•
Impairment of Oil and Gas Properties — We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Due to the uncertainty inherent in these factors, we cannot predict the amount of impairment charges that may be recorded in the future.
•
Oil and Gas Reserves — The estimation of oil and gas reserves is a significant estimate which affects the amount of non-cash depletion expense we record as well as impairment analysis we perform. On an annual basis, we engage an independent petroleum engineering firm to assist us in preparing estimates of crude oil and gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Oil and gas prices are volatile and largely affected by worldwide or domestic production and consumption and are outside our control.
•
Asset Retirement Obligations — We make estimates of the future costs of the retirement obligations of our producing oil and gas properties. Estimating future costs involves significant assumptions and judgments regarding such factors as estimated costs of plugging and abandonment, timing of settlements, discount rates and inflation rates. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.
•
Impairment of Goodwill — Measuring goodwill for impairment annually requires estimation of future cash flows and determination of fair values using many assumptions and inputs, including estimated future selling prices and volumes, estimated future costs to develop and explore, observable market inputs, weighted average cost of capital, estimated operating expenses and various other projected economic factors. Changes in economic and operating conditions can affect these assumptions and could result in additional interim testing and goodwill impairment charges in the future periods.
•
Share-Based Compensation — We use the Black-Scholes option pricing model to determine the fair value of stock options. The determination of the fair value of share-based payment awards on the date of grant using an option-pricing model is affected by the stock price as well as assumptions regarding a number of other variables. These variables include expected stock price volatility over the term of the awards, actual and projected employee stock option exercise behaviors (term of option), risk-free interest rate and expected dividends. We have limited historical experience as a stand-alone company so we utilized alternative methods in determining our valuation assumptions.

52


The expected life was based on the simplified method utilizing the midpoint between the vesting period and the contractual life of the awards. The expected stock price volatility was based on our historical volatility of our common stock for a period corresponding to the expected life of the options. Pre-vesting forfeitures are estimated based upon the pool of participants and their expected activity and historical trends. We use Monte Carlo simulation pricing model to determine the fair value of market-leveraged stock units (MSU's) and stock option awards with market condition. A typical Monte Carlo exercise simulates a distribution of stock prices to yield an expected distribution of stock prices at the end of the performance period. The simulations are repeated many times in order to derive a probabilistic assessment of stock performance. The stock-paths are simulated using assumptions which include expected stock price volatility and risk-free interest rate.
•
Income Taxes — In preparing our consolidated financial statements, significant judgment is required to estimate our income taxes. Our estimates are based on our interpretation of federal and state tax laws. We estimate our actual current tax due and assess temporary and permanent differences resulting from differing treatment of items for tax and accounting purposes. The temporary differences result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. If needed, we record a valuation allowance against our deferred tax assets. In addition, when we believe a tax position is supportable but the outcome uncertain, we include the item in our tax return but do not recognize the related benefit in our provision for taxes. Instead, we record a reserve for unrecognized tax benefits, which represents our expectation of the most likely outcome considering the technical merits and specific facts of the position. Changes to liabilities are only made when an event occurs that changes the most likely outcome, such as settlement with the relevant tax authority, expiration of statutes of limitations, changes in tax law, or recent court rulings. Adjustments to temporary differences, permanent differences or uncertain tax positions could materially impact our financial position, cash flow and results of operation.
Adopted and Pending Accounting Pronouncements
We did not adopt any new accounting pronouncements in 2015. Please read Note 2 — New and Pending Accounting Pronouncements to the Consolidated Financial Statements.
Effects of Inflation
Inflation has had minimal effects on operating results the past three years.
Legal Proceedings
We are involved in various legal proceedings that arise from time to time in the ordinary course of doing business. We believe we have established adequate reserves for any probable losses, and we do not believe that the outcome of any of these proceedings should have a material adverse effect on our financial position, long-term results of operations, or cash flow. It is possible, however, that charges related to these matters could be significant to results of operations or cash flows in any one accounting period.


53


Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
Interest Rate Risk
Our interest rate risk is principally related to our variable-rate debt. Interest rate changes impact earnings due to the resulting increase or decrease in our variable-rate debt, which was $43,692,000 at year-end 2015.
The following table illustrates the estimated effect on our pre-tax income of immediate, parallel, and sustained shifts in interest rates for the next 12 months on our variable-rate debt at year-end 2015. This estimate assumes that debt reductions from contractual payments will be replaced with short-term, variable-rate debt; however, that may not be the financing alternative we choose.
 
Year-End
Change in Interest Rates
2015
 
(In thousands)
2%
$
(702
)
1%
$
(259
)
(1)%
$
410

(2)%
$
820

Foreign Currency Risk
We have no exposure to foreign currency fluctuations.
Commodity Price Risk
We have exposure to commodity price fluctuations from our oil and gas production which can materially affect our revenues and cash flows. The prices we receive for our production depend on numerous factors beyond our control. Based on our 2015 production, a 10% decrease in our average realized price received for oil and gas would have reduced our oil and gas production revenues by $5,156,000. To manage our exposure to commodity price risks associated with the sale of oil and gas, we may periodically enter into derivative hedging transactions for a portion of our estimated production. We do not have any commodity derivative positions outstanding at year-end 2015.


54


Item 8.
Financial Statements and Supplementary Data.
Index to Financial Statements
 
 
Page
Audited Financial Statements
 
Financial Statement Schedule
 

55


MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Forestar is responsible for establishing and maintaining adequate internal control over financial reporting. Management has designed our internal control over financial reporting to provide reasonable assurance that our published financial statements are fairly presented, in all material respects, in conformity with generally accepted accounting principles.
Management is required by paragraph (c) of Rule 13a-15 of the Securities Exchange Act of 1934, as amended, to assess the effectiveness of our internal control over financial reporting as of each year end. In making this assessment, management used the Internal Control — Integrated Framework (2013) by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Management conducted the required assessment of the effectiveness of our internal control over financial reporting as of year-end. Based upon this assessment, management believes that our internal control over financial reporting is effective as of year-end 2015.
Ernst & Young LLP, the independent registered public accounting firm that audited our financial statements included in this Form 10-K, has also audited our internal control over financial reporting. Their attestation report follows this report of management.

56


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Forestar Group Inc.

We have audited Forestar Group Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Forestar Group Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Forestar Group Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Forestar Group Inc. as of December 31, 2015 and 2014, and the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2015 of Forestar Group Inc. and our report dated March 4, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP
Austin, Texas
March 4, 2016

57


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Forestar Group Inc.

We have audited the accompanying consolidated balance sheets of Forestar Group Inc. as of December 31, 2015 and 2014, and the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Schedule III. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Forestar Group Inc. at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Forestar Group Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 4, 2016 expressed an unqualified opinion thereon.


/s/ Ernst & Young LLP
Austin, Texas
March 4, 2016


58


FORESTAR GROUP INC.
CONSOLIDATED BALANCE SHEETS
 
 
At Year-End
 
2015
 
2014
 
(In thousands, except
share data)
ASSETS
 
 
 
Cash and cash equivalents
$
96,442

 
$
170,127

Real estate, net
586,715

 
575,756

Oil and gas properties and equipment, net
80,613

 
263,493

Investment in unconsolidated ventures
82,453

 
65,005

Timber
7,683

 
8,315

Receivables, net
23,656

 
24,589

Income taxes receivable
12,056

 
7,503

Prepaid expenses
3,213

 
6,000

Property and equipment, net
10,732

 
11,627

Deferred tax asset, net
—

 
40,624

Goodwill and other intangible assets
63,128

 
66,131

Other assets
13,822

 
19,029

TOTAL ASSETS
$
980,513

 
$
1,258,199

LIABILITIES AND EQUITY
 
 
 
Accounts payable
$
11,959

 
$
20,400

Accrued employee compensation and benefits
5,547

 
8,323

Accrued property taxes
4,788

 
5,966

Accrued interest
3,267

 
3,451

Deferred tax liability, net
1,037

 
—

Earnest money deposits
10,214

 
10,045

Other accrued expenses
23,481

 
35,729

Other liabilities
26,323

 
31,799

Debt
389,782

 
432,744

TOTAL LIABILITIES
476,398

 
548,457

COMMITMENTS AND CONTINGENCIES

 

EQUITY
 
 
 
Forestar Group Inc. shareholders’ equity:
 
 
 
Common stock, par value $1.00 per share, 200,000,000 authorized shares, 36,946,603 issued at December 31, 2015 and December 31, 2014
36,947

 
36,947

Additional paid-in capital
561,850

 
558,945

Retained earnings (Accumulated deficit)
(46,046
)
 
167,001

Treasury stock, at cost, 3,203,768 shares at December 31, 2015 and 3,485,278 shares at December 31, 2014
(51,151
)
 
(55,691
)
Total Forestar Group Inc. shareholders’ equity
501,600

 
707,202

Noncontrolling interests
2,515

 
2,540

TOTAL EQUITY
504,115

 
709,742

TOTAL LIABILITIES AND EQUITY
$
980,513

 
$
1,258,199

Please read the notes to the consolidated financial statements.


59


FORESTAR GROUP INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
 
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands, except per share amounts)
REVENUES
 
 
 
 
 
Real estate sales and other
$
120,022

 
$
171,672

 
$
152,684

Commercial and income producing properties
82,808

 
41,440

 
95,327

Real estate
202,830

 
213,112

 
248,011

Oil and gas
52,939

 
84,300

 
72,313

Other natural resources
6,652

 
9,362

 
10,721

 
262,421

 
306,774

 
331,045

COST AND EXPENSES
 
 
 
 
 
Cost of real estate sales and other
(52,640
)
 
(86,432
)
 
(76,628
)
Cost of commercial and income producing properties
(61,251
)
 
(37,332
)
 
(80,166
)
Cost of oil and gas producing activities
(224,400
)
 
(98,371
)
 
(42,067
)
Cost of other natural resources
(3,081
)
 
(3,006
)
 
(2,033
)
Other operating
(59,359
)
 
(58,683
)
 
(60,359
)
General and administrative
(27,253
)
 
(22,230
)
 
(28,376
)
 
(427,984
)
 
(306,054
)
 
(289,629
)
GAIN ON SALE OF ASSETS
879

 
38,038

 
5,161

OPERATING INCOME (LOSS)
(164,684
)
 
38,758

 
46,577

Equity in earnings of unconsolidated ventures
16,008

 
8,685

 
8,737

Interest expense
(34,066
)
 
(30,286
)
 
(20,004
)
Other non-operating income
3,006

 
8,588

 
6,959

INCOME (LOSS) BEFORE TAXES
(179,736
)
 
25,745

 
42,269

Income tax expense
(32,635
)
 
(8,657
)
 
(7,208
)
CONSOLIDATED NET INCOME (LOSS)
(212,371
)
 
17,088

 
35,061

Less: Net (income) attributable to noncontrolling interests
(676
)
 
(505
)
 
(5,740
)
NET INCOME (LOSS) ATTRIBUTABLE TO FORESTAR GROUP INC.
$
(213,047
)
 
$
16,583

 
$
29,321

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
 
 
 
 
 
Basic
34,266

 
35,317

 
35,365

Diluted
34,266

 
43,596

 
36,813

NET INCOME (LOSS) PER COMMON SHARE
 
 
 
 
 
Basic
$
(6.22
)
 
$
0.38

 
$
0.81

Diluted
$
(6.22
)
 
$
0.38

 
$
0.80

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO FORESTAR GROUP INC.
$
(213,047
)
 
$
16,583

 
$
29,321

Please read the notes to the consolidated financial statements.

60


FORESTAR GROUP INC.
CONSOLIDATED STATEMENTS OF EQUITY
 
 
 
Forestar Group Inc. Shareholders' Equity
 
 
 
 
 
Common Stock
 
Additional
Paid-in
Capital
 
Treasury Stock
 
Retained Earnings (Accumulated Deficit)
 
Non-controlling
Interests
 
Total
 
Shares
 
Amount
 
Shares
 
Amount
 
(In thousands, except per share amounts)
Balance at December 31, 2012
$
533,547

 
36,946,603

 
$
36,947

 
$
407,206

 
(2,327,623
)
 
$
(35,762
)
 
$
121,097

 
$
4,059

Net income
35,061

 
—

 
—

 
—

 
—

 
—

 
29,321

 
5,740

Distributions to noncontrolling interest
(7,269
)
 
—

 
—

 
—

 
—

 
—

 
—

 
(7,269
)
Contributions from noncontrolling interest
3,022

 
—

 
—

 
—

 
—

 
—

 
—

 
3,022

Issuances of common stock for vested share-settled units
2,871

 
—

 
—

 
2,721

 
7,298

 
150

 
—

 
—

Convertible note issuance proceeds, net of issuance costs and taxes
17,058

 
—

 
—

 
17,058

 
—

 
—

 
—

 
—

TEU issuance proceeds, net of issuance costs - 6,000,000 units
120,335

 
—

 
—

 
120,335

 
—

 
—

 
—

 
—

Issuances from exercises of pre-spin stock options, net of swaps
1,423

 
—

 
—

 
(515
)
 
136,253

 
1,938

 
—

 
—

Issuances from exercises of stock options, net of swaps
683

 
—

 
—

 
66

 
53,611

 
617

 
—

 
—

Shares withheld for payroll taxes
(1,137
)
 
—

 
—

 
(8
)
 
(59,219
)
 
(1,129
)
 
—

 
—

Forfeitures of restricted stock awards
—

 
—

 
—

 
10

 
(9,986
)
 
(10
)
 
—

 
—

Share-based compensation
9,911

 
—

 
—

 
9,911

 
—

 
—

 
—

 
—

Tax benefit from exercise of restricted stock units and stock options and vested restricted stock
(108
)
 
—

 
—

 
(108
)
 
—

 
—

 
—

 
—

Balance at December 31, 2013
$
715,397

 
36,946,603

 
$
36,947

 
$
556,676

 
(2,199,666
)
 
$
(34,196
)
 
$
150,418

 
$
5,552

Net income
17,088

 
—

 
—

 
—

 
—

 
—

 
16,583

 
505

Distributions to noncontrolling interest
(4,171
)
 
—

 
—

 
—

 
—

 
—

 
—

 
(4,171
)
Contributions from noncontrolling interest
2,585

 
—

 
—

 
—

 
—

 
—

 
—

 
2,585

Dissolution of noncontrolling interests
1,342

 
—

 
—

 
—

 
—

 
—

 
—

 
1,342

Purchase of noncontrolling interests, net
(6,242
)
 
—

 
—

 
(2,969
)
 
—

 
—

 
—

 
(3,273
)
Issuances of common stock for vested share-settled units
—

 
—

 
—

 
(2,567
)
 
164,914

 
2,567

 
—

 
—

Issuances from exercises of pre-spin stock options, net of swaps
877

 
—

 
—

 
(43
)
 
60,823

 
920

 
—

 
—

Issuances from exercises of stock options, net of swaps
329

 
—

 
—

 
(333
)
 
45,062

 
662

 
—

 
—

Shares withheld for payroll taxes
(1,043
)
 
—

 
—

 
(4
)
 
(55,238
)
 
(1,039
)
 
—

 
—

Shares repurchased
(24,595
)
 
—

 
—

 
—

 
(1,491,187
)
 
(24,595
)
 
—

 
—

Forfeitures of restricted stock awards
—

 
—

 
—

 
10

 
(9,986
)
 
(10
)
 
—

 
—

Share-based compensation
8,033

 
—

 
—

 
8,033

 
—

 
—

 
—

 
—

Tax benefit from exercise of restricted stock units and stock options and vested restricted stock
142

 
—

 
—

 
142

 
—

 
—

 
—

 
—

Balance at December 31, 2014
$
709,742

 
36,946,603

 
$
36,947

 
$
558,945

 
(3,485,278
)
 
$
(55,691
)
 
$
167,001

 
$
2,540

Net income (loss)
(212,371
)
 
—

 
—

 
—

 
—

 
—

 
(213,047
)
 
676

Distributions to noncontrolling interests
(701
)
 
—

 
—

 
—

 
—

 
—

 
—

 
(701
)
Issuances of common stock for vested share-settled units
—

 
—

 
—

 
(5,362
)
 
335,611

 
5,362

 
—

 
—

Issuances from exercises of pre-spin stock options
31

 
—

 
—

 
(33
)
 
3,999

 
64

 
—

 
—

Shares withheld for payroll taxes
(762
)
 
—

 
—

 
(1
)
 
(51,521
)
 
(761
)
 
—

 
—

Forfeitures of restricted stock awards
—

 
—

 
—

 
125

 
(6,579
)
 
(125
)
 
—

 
—

Share-based compensation
8,576

 
—

 
—

 
8,576

 
—

 
—

 
—

 
—

Tax benefit from exercise of restricted stock units and stock options and vested restricted stock
(400
)
 
—

 
—

 
(400
)
 
—

 
—

 
—

 
—

Balance at December 31, 2015
$
504,115

 
36,946,603

 
$
36,947

 
$
561,850

 
(3,203,768
)
 
$
(51,151
)
 
$
(46,046
)
 
$
2,515

Please read the notes to the consolidated financial statements.

61


FORESTAR GROUP INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
Consolidated net income (loss)
$
(212,371
)
 
$
17,088

 
$
35,061

Adjustments:
 
 
 
 
 
Depreciation, depletion and amortization
45,085

 
41,715

 
29,980

Change in deferred income taxes
41,261

 
1,645

 
5,389

Change in unrecognized tax benefits
—

 
—

 
(6,251
)
Equity in earnings of unconsolidated ventures
(16,008
)
 
(8,685
)
 
(8,737
)
Distributions of earnings of unconsolidated ventures
12,741

 
5,721

 
6,360

Share-based compensation
4,246

 
3,417

 
16,809

Real estate cost of sales
87,733

 
84,665

 
104,899

Dry hole and unproved leasehold impairment costs
67,639

 
29,528

 
5,837

Real estate development and acquisition expenditures, net
(107,988
)
 
(114,694
)
 
(106,609
)
Reimbursements from utility and improvement districts
15,176

 
66,047

 
9,945

Asset impairments
108,184

 
15,934

 
1,790

Gain on sale of assets
(879
)
 
(38,038
)
 
(5,161
)
Other
4,680

 
5,887

 
2,391

Changes in:
 
 
 
 
 
Notes and accounts receivables
(978
)
 
10,704

 
(3,864
)
Prepaid expenses and other
3,026

 
2,180

 
(795
)
Accounts payable and other accrued liabilities
(11,868
)
 
(4,653
)
 
(1,557
)
Income taxes
(4,553
)
 
(11,379
)
 
3,290

Net cash provided by operating activities
35,126

 
107,082

 
88,777

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
Property, equipment, software, reforestation and other
(14,690
)
 
(16,398
)
 
(11,828
)
Oil and gas properties and equipment
(49,717
)
 
(101,145
)
 
(96,069
)
Acquisition of partner's interest in unconsolidated multifamily venture, net of cash
—

 
(20,155
)
 
—

Acquisition of oil and gas properties
—

 
(1,100
)
 
—

Investment in unconsolidated ventures
(26,349
)
 
(14,692
)
 
(857
)
Proceeds from sale of assets
18,260

 
21,962

 
1,333

Return of investment in unconsolidated ventures
12,168

 
1,797

 
3,494

Net cash (used for) investing activities
(60,328
)
 
(129,731
)
 
(103,927
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
Proceeds from issuance of convertible senior notes, net
—

 
—

 
120,795

Proceeds from issuance of senior secured notes, net
—

 
241,947

 
—

Proceeds from issuance of tangible equity units, net
—

 
—

 
144,998

Payments of debt
(58,220
)
 
(225,481
)
 
(106,076
)
Additions to debt
11,463

 
22,593

 
43,911

Deferred financing fees
(295
)
 
(3,217
)
 
(438
)
Distributions to noncontrolling interests, net
(701
)
 
(3,146
)
 
(7,154
)
Purchase of noncontrolling interests
—

 
(7,971
)
 
—

Exercise of stock options
31

 
1,206

 
2,106

Repurchases of common stock
—

 
(24,595
)
 
—

Payroll taxes on restricted stock and stock options
(762
)
 
(1,043
)
 
(1,137
)
Excess income tax benefit from share-based compensation
1

 
176

 
91

Net cash (used for) provided by financing activities
(48,483
)
 
469

 
197,096

Net (decrease) increase in cash and cash equivalents
(73,685
)
 
(22,180
)
 
181,946

Cash and cash equivalents at beginning of year
170,127

 
192,307

 
10,361

Cash and cash equivalents at year-end
$
96,442

 
$
170,127

 
$
192,307

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
 
 
 
 
 
Cash paid during the year for:
 
 
 
 
 
Interest
$
27,330

 
$
22,936

 
$
13,818

Income taxes paid (refunds)
$
(4,077
)
 
$
18,322

 
$
4,955

SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
 
 
 
 
 
Capitalized interest
$
2,938

 
$
1,154

 
$
816

Noncontrolling interests
$
—

 
$
2,904

 
$
2,907

Please read the notes to the consolidated financial statements.

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FORESTAR GROUP INC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements include the accounts of Forestar Group Inc., all subsidiaries, ventures and other entities in which we have a controlling interest. We account for our investment in other entities in which we have significant influence over operations and financial policies using the equity method (we recognize our share of the entities’ income or loss and any preferential returns and treat distributions as a reduction of our investment). We eliminate all material intercompany accounts and transactions. Noncontrolling interests in consolidated pass-through entities are recognized before income taxes.
We prepare our financial statements in accordance with generally accepted accounting principles in the United States, which require us to make estimates and assumptions about future events. Actual results can, and probably will, differ from those we currently estimate. Examples of significant estimates include those related to allocating costs to real estate, measuring long-lived assets for impairment, oil and gas revenue accruals, capital expenditure and lease operating expense accruals associated with our oil and gas production activities, oil and gas reserves and depletion of our oil and gas properties.
Cash and Cash Equivalents
Cash and cash equivalents include cash and other short-term instruments with original maturities of three months or less. At year-end 2015 and 2014, restricted cash was $200,000 and $217,000 and is included in other assets.
Cash Flows
Expenditures for the acquisition and development of single-family and multifamily real estate that we intend to develop for sale are classified as operating activities. Expenditures for the acquisition and development of properties to be held and operated, investment in oil and gas properties and equipment, and business acquisitions are classified as investing activities. Our accrued capital expenditures for unproved leasehold acquisitions and drilling and completion costs at year-end 2015 and 2014 were $7,033,000 and $19,405,000 and are included in other accrued expenses in our consolidated balance sheets. These oil and gas property additions will be reflected as cash used for investing activities in the period the accrued payables are settled.
Capitalized Software
We capitalize purchased software costs as well as the direct internal and external costs associated with software we develop for our own use. We amortize these capitalized costs using the straight-line method over estimated useful lives generally ranging from three to five years. The carrying value of capitalized software was $237,000 at year-end 2015 and $1,188,000 at year-end 2014 and is included in other assets. The amortization of these capitalized costs was $996,000 in 2015, $1,067,000 in 2014 and $1,593,000 in 2013 and is included in general and administrative and operating expenses.
Environmental and Asset Retirement Obligations
We recognize environmental remediation liabilities on an undiscounted basis when environmental assessments or remediation are probable and we can reasonably estimate the cost. We adjust these liabilities as further information is obtained or circumstances change. Our asset retirement obligations are related to the abandonment and site restoration requirements that result from the acquisition, construction and development of our oil and gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income (loss).

63


The following summarizes the changes in asset retirement obligations:
 
Year-End
 
2015
 
2014
 
(In thousands)
Beginning balance
$
1,807

 
$
1,483

Additions
65

 
314

Property dispositions
(119
)
 
(230
)
Change in estimate
—

 
118

Liabilities settled
(139
)
 
—

Accretion expense
144

 
122

 
$
1,758

 
$
1,807

Fair Value Measurements
Financial instruments for which we did not elect the fair value option include cash and cash equivalents, accounts and notes receivables, other assets, long-term debt, accounts payable and other liabilities. With the exception of long-term notes receivable and debt, the carrying amounts of these financial instruments approximate their fair values due to their short-term nature or variable interest rates.
Goodwill and Other Intangible Assets
We record goodwill when the purchase price of a business acquisition exceeds the estimated fair value of net identified tangible and intangible assets acquired. We do not amortize goodwill or other indefinite lived intangible assets. Instead, we measure these assets for impairment based on the estimated fair values at least annually or more frequently if impairment indicators exist. We perform the annual impairment measurement in the fourth quarter of each year. Intangible assets with finite useful lives are amortized over their estimated useful lives.
In 2015, we performed our annual goodwill impairment evaluation and concluded that goodwill was not impaired as the estimated fair value exceeded the carrying value.
Income Taxes
We provide deferred income taxes using current tax rates for temporary differences between the financial accounting carrying value of assets and liabilities and their tax accounting carrying values. We recognize and value income tax exposures for the various taxing jurisdictions where we operate based on laws, elections, commonly accepted tax positions, and management estimates. We include tax penalties and interest in income tax expense. We provide a valuation allowance for any deferred tax asset that is not likely to be recoverable in future periods.
When we believe a tax position is supportable but the outcome uncertain, we include the item in our tax return but do not recognize the related benefit in our provision for taxes. Instead, we record a reserve for unrecognized tax benefits, which represents our expectation of the most likely outcome considering the technical merits and specific facts of the position. Changes to liabilities are only made when an event occurs that changes the most likely outcome, such as settlement with the relevant tax authority, expiration of statutes of limitations, changes in tax law, or recent court rulings.
Owned Mineral Interests
When we lease our mineral interests to third-party exploration and production entities, we retain a royalty interest and may take an additional participation in production, including a working interest. Mineral interests and working interests related to our owned mineral interests are included in oil and gas properties and equipment on our balance sheet, net of accumulated depletion.
Oil and Gas Properties
We use the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests leased, costs to drill and complete development of oil and gas wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves and if determined incapable of producing commercial quantities of oil and gas these costs are expensed as dry hole costs. At year-end 2014, we had $8,575,000 in capitalized exploratory well costs pending determination of proved reserves, of which $8,454,000 was charged to expense in 2015 with the remaining capitalized based on determination of proved reserves. At year-end 2015, we have no capitalized exploratory well costs pending determination of proved reserves. Exploration costs include dry hole costs, geological and geophysical costs, expired unproved leasehold costs and seismic studies, and are expensed as incurred. Production costs incurred to maintain wells and related equipment are charged to expense as incurred.

64


Depreciation and depletion of producing oil and gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible drilling and completion costs. Proved reserves are used to compute unit rates for unamortized acquisition of proved leasehold costs. Unit-of-production amortization rates are revised whenever there is an indication of the need for revision but at least once a year and those revisions are accounted for prospectively as changes in accounting estimates.
Impairment of Oil and Gas Properties
We evaluate our oil and gas properties, including facilities and equipment, for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
The assessment of unproved leasehold properties to determine any possible impairment requires significant judgment. We assess our unproved leasehold properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Impairment expense for proved and unproved oil and gas properties are included in costs of oil and gas producing activities.
Operating Leases
We occupy office space in various locations under operating leases. The lease agreements may contain rent escalation clauses, construction allowances and/or contingent rent provisions. We expense operating leases ratably over the shorter of the useful life or the lease term. For scheduled rent escalation clauses, we recognize the base rent expense on a straight-line basis and record the difference between the recognized rent expense and the amounts payable under the lease as deferred lease credits included in other liabilities in the consolidated balance sheets. Deferred lease credits are amortized over the lease term. For construction allowances, we record leasehold improvement assets included in property and equipment in the consolidated balance sheets amortized over the shorter of their economic lives or the lease term. The related deferred lease credits are amortized as a reduction of rent expense over the lease term.
Property and Equipment
We carry property and equipment at cost less accumulated depreciation. We capitalize the cost of significant additions and improvements, and we expense the cost of repairs and maintenance. We capitalize interest costs incurred on major construction projects. We depreciate these assets using the straight-line method over their estimated useful lives as follows:
 
Estimated
 
Year-End
 
Useful Lives
 
2015
 
2014
 
 
 
(In thousands)
Buildings and building improvements
10 to 40 years
 
$
4,044

 
$
4,461

Property and equipment
2 to 10 years
 
12,230

 
14,084

 
 
 
16,274

 
18,545

Less: accumulated depreciation
 
 
(5,542
)
 
(6,918
)
 
 
 
$
10,732

 
$
11,627

Depreciation expense of property and equipment was $1,067,000 in 2015, $903,000 in 2014 and $1,028,000 in 2013.
Real Estate
We carry real estate at the lower of cost or fair value less cost to sell. We capitalize interest costs once development begins, and we continue to capitalize throughout the development period. We also capitalize infrastructure, improvements, amenities, and other development costs incurred during the development period. We determine the cost of real estate sold using the relative sales value method. When we sell real estate from projects that are not finished, we include in the cost of real estate sold estimates of future development costs through completion, allocated based on relative sales values. These estimates of future development costs are reevaluated at least annually, with any adjustments being allocated prospectively to the remaining

65


units available for sale. We receive cash deposits from home builders for purchases of vacant developed lots from community development projects. These earnest money deposits are released to the home builders as lots are developed and sold.
Income producing properties are carried at cost less accumulated depreciation computed using the straight-line method over their estimated useful lives.
We have agreements with utility or improvement districts, principally in Texas, whereby we agree to convey to the district's water, sewer and other infrastructure-related assets we have constructed in connection with projects within their jurisdiction. The reimbursement for these assets ranges from 70 to 90 percent of allowable cost as defined by the district. The transfer is consummated and we receive payment when the districts have a sufficient tax base to support funding of their bonds. The cost we incur in constructing these assets is included in capitalized development costs, and upon collection, we remove the assets from capitalized development costs. We provide an allowance to reflect our past experiences related to claimed allowable development costs.
Impairment of Real Estate Long-Lived Assets
We review real estate long-lived assets held for use for impairment when events or circumstances indicate that their carrying value may not be recoverable. Impairment exists if the carrying amount of the long-lived asset is not recoverable from the undiscounted cash flows expected from its use and eventual disposition. We determine the amount of the impairment loss by comparing the carrying value of the long-lived asset to its estimated fair value. In the absence of quoted market prices, we determine estimated fair value generally based on the present value of future probability weighted cash flows expected from the sale of the long-lived asset. Non-cash impairment charges related to our owned and consolidated real estate assets are included in cost of real estate sales and other.
Revenue
Real Estate
We recognize revenue from sales of real estate when a sale is consummated, the buyer’s initial investment is adequate, any receivables are probable of collection, the usual risks and rewards of ownership have been transferred to the buyer, and we do not have significant continuing involvement with the real estate sold. If we determine that the earnings process is not complete, we defer recognition of any gain until earned. We recognize revenue from hotel room sales and other guest services when rooms are occupied and other guest services have been rendered. We recognize rental revenues from our multifamily properties when earned in accordance with the terms of the respective leases on a straight-line basis for the period of occupancy.
We recognize construction revenues on multifamily projects that we develop as a general contractor. Construction revenues are recognized as costs are incurred plus fixed fee earned. We are reimbursed for costs paid to subcontractors plus we may earn a development and construction management fee on multifamily projects we develop, both of which are included in commercial and income producing properties revenue. On multifamily projects where our fee is based on a fixed fee plus guaranteed maximum price contract, any cost overruns incurred during construction, as compared to the original budget, will reduce the net fee generated on these projects. Any excess cost overruns estimated over the net fee generated are recognized in the period in which they become evident. At year-end 2015, we are not a general contractor on any of the multifamily projects currently under construction and we do not anticipate to be a general contractor on any new multifamily projects.
We exclude from revenue amounts we collect from utility or improvement districts related to the conveyance of water, sewer and other infrastructure related assets. We also exclude from revenue amounts we collect for timber sold on land being developed. These proceeds reduce capitalized development costs. We exclude from revenue amounts we collect from customers that represent sales tax or other taxes that are based on the sale. These amounts are included in other accrued expenses until paid.
Oil and Gas
We recognize revenue as oil and gas is produced and sold. There are a significant amount of oil and gas properties which we do not operate and, therefore, revenue is typically recorded in the month of production based on an estimate of our share of volumes produced and prices realized. We obtain the most current available production data from the operators and price indices for each well to estimate the accrual of revenue. Obtaining production data on a timely basis for some wells is not feasible; therefore we utilize past production receipts and estimated sales price information to estimate accrual of working interest revenue on all other non-operated wells each month. Revisions to such estimates are recorded as actual results become known. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible.
A majority of our sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined upon a percentage

66


of pre-determined and published monthly index price. The terms of these contracts have not had an effect on how we recognize revenue.
We recognize revenue from mineral bonus payments received as a result of leasing our owned mineral interests to others when we have received an executed agreement with the exploration company transferring the rights to any oil or gas it may find and requiring drilling be done within a specified period, the payment has been collected, and we have no obligation to refund the payment. We recognize revenue from delay rentals received if drilling has not started within the specified period and when the payment has been collected. We recognize revenue from mineral royalties when the minerals have been delivered to the buyer, the value is determinable, and we are reasonably sure of collection.
Other Natural Resources
We recognize revenue from timber sales upon passage of title, which occurs at delivery; when the price is fixed and determinable; and we are reasonably sure of collection. We recognize revenue from recreational leases on the straight-line basis over the lease term. We recognize revenue from the sale of water rights or groundwater reservation agreements upon receipt of an executed agreement and payment has been collected and all conditions to the agreement have been met and we have no further performance obligations to meet. The water delivery revenues will be recognized as water is being delivered and metered at the delivery point.
Share-Based Compensation
We use the Black-Scholes option pricing model for stock options, Monte Carlo simulation pricing model for market-leveraged stock units and for stock options with market conditions, grant date fair value for equity-settled awards and period-end fair value for cash-settled awards. We expense share-based awards ratably over the vesting period or earlier based on retirement eligibility.
Timber
We carry timber at cost less the cost of timber cut. We expense the cost of timber cut based on the relationship of the timber carrying value to the estimated volume of recoverable timber multiplied by the amount of timber cut. We include the cost of timber cut in cost of other natural resources in the income statement. We determine the estimated volume of recoverable timber using statistical information and other data related to growth rates and yields gathered from physical observations, models and other information gathering techniques. Changes in yields are generally due to adjustments in growth rates and similar matters and are accounted for prospectively as changes in estimates. We capitalize reforestation costs incurred in developing viable seedling plantations (up to two years from planting), such as site preparation, seedlings, planting, fertilization, insect and wildlife control, and herbicide application. We expense all other costs, such as property taxes and costs of forest management personnel, as incurred. Once the seedling plantation is viable, we expense all costs to maintain the viable plantations, such as fertilization, herbicide application, insect and wildlife control, and thinning, as incurred.
We own directly or through ventures about 89,000 acres of non-core timberland and undeveloped land, primarily in Georgia. The non-cash cost of timber cut and sold is $250,000 in 2015, $371,000 in 2014 and $609,000 in 2013 and is included in depreciation, depletion and amortization in our statement of cash flows.

Note 2 — Pending Accounting Pronouncements
Pending Accounting Standards
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for annual and interim periods beginning after December 15, 2016. In July 2015, the FASB decided to defer the effective date of the new standard by one year. This deferral results in the updated standard being effective after December 15, 2017. We have not yet selected a transition method and we are currently evaluating the effect that the updated standard will have on our earnings, financial position and disclosures.
In January 2015, the FASB issued ASU 2015-01, Income Statement - Extraordinary and Unusual Items (Subtopic 225-20), which eliminates the concept of extraordinary items from U.S. GAAP. The updated standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.
In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis (Topic 810), requiring entities to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation

67


under the revised consolidation model. The revised consolidation model: (1) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, (3) affects the consolidation analysis of reporting entities that are involved with VIEs, and (4) provides a scope exception from consolidation guidance for reporting entities with interests in certain legal entities. The updated standard is effective for financial statements issued for annual and interim periods beginning after December 15, 2015. Early adoption is permitted. The updated standard may be applied retrospectively or using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as part of its initiative to reduce complexity in accounting standards. To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update), which allows an entity to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The updated standards are effective for financial statements issued for annual and interim periods beginning after December 15, 2015. The updated standards are not expected to materially impact our financial position or disclosures.
In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40), in order to provide clarification on whether a cloud computing arrangement includes a software license. If a software license is included, the customer should account for the license consistent with its accounting of other software licenses. If a software license is not included, the arrangement should be accounted for as a service contract. The update is effective for reporting periods beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.
In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Updates. The amendments in this update cover a wide range of topics in the codification and are generally categorized as follows: Amendments Related to Differences between Original Guidance and the Codification; Guidance Clarification and Reference Corrections; Simplification; and, Minor Improvements. The amendments are effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The adoption of this standard is not expected to impact our financial position or results of operations.
In November 2015, the FASB issued ASU 2015-17, Income Taxes - Balance Sheet Classification of Deferred Taxes (Subtopic 740). The ASU requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The amendments in this update are effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2016. We do not currently present a classified consolidated balance sheet and therefore this pronouncement will have no impact on our financial statements and related disclosures.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessees to put most leases on their balance sheets but recognize expenses on their income statements in a manner that is similar to today's accounting. This guidance also eliminates today's real estate-specific provisions for all entities. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. This guidance is effective in 2019, and interim periods within that year. Early adoption is permitted. The new leases standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.


68


Note 3 — Goodwill and Other Intangible Assets
Carrying value of goodwill and other intangible assets follows:
 
Year-End
 
2015
 
2014
 
(In thousands)
Goodwill
$
61,164

 
$
63,423

Identified intangibles, net
1,964

 
2,708

 
$
63,128

 
$
66,131

Goodwill related to oil and gas properties is $57,290,000 and $59,549,000 at year-end 2015 and 2014. Goodwill associated with our water resources initiatives is $3,874,000 at year-end 2015 and 2014. The change in goodwill for oil and gas properties is related to goodwill allocated to properties sold in 2015.
Identified intangibles include $1,681,000 in indefinite lived groundwater leases associated with our water resources initiatives and $283,000 related to patents with definite lives associated with the Calliope Gas Recovery System, a process to increase natural gas production.

Note 4 — Real Estate
Real estate consists of:
 
Year-End 2015
 
Year-End 2014
 
Carrying Value
 
Accumulated Depreciation
 
Net Carrying Value
 
Carrying Value
 
Accumulated Depreciation
 
Net Carrying Value
 
(In thousands)
Entitled, developed and under development projects
$
352,141

 
$
—

 
$
352,141

 
$
321,273

 
$
—

 
$
321,273

Undeveloped land (includes land in entitlement)
98,181

 
—

 
98,181

 
93,182

 
—

 
93,182

Commercial
 
 
 
 
 
 
 
 
 
 
 
Radisson Hotel & Suites
62,889

 
(29,268
)
 
33,621

 
59,773

 
(29,062
)
 
30,711

Harbor Lakes golf course and country club (a)
—

 
—

 
—

 
2,054

 
(1,508
)
 
546

Income producing properties
 
 
 
 
 
 
 
 
 
 
 
Eleven
53,896

 
(2,861
)
 
51,035

 
53,958

 
(576
)
 
53,382

Midtown (a)
—

 
—

 
—

 
33,293

 
(231
)
 
33,062

Dillon
19,987

 
—

 
19,987

 
15,203

 
—

 
15,203

Music Row
9,947

 
—

 
9,947

 
7,675

 
—

 
7,675

Downtown Edge
12,706

 
—

 
12,706

 
11,856

 
—

 
11,856

West Austin
9,097

 
—

 
9,097

 
8,866

 
—

 
8,866

 
$
618,844

 
$
(32,129
)
 
$
586,715

 
$
607,133

 
$
(31,377
)
 
$
575,756

 _________________________
(a) 
Sold in 2015.
Our estimated cost of assets for which we expect to be reimbursed by utility and improvement districts were $67,554,000 at year-end 2015 and $65,212,000 at year-end 2014, including $22,302,000 at year-end 2015 and $31,913,000 at year-end 2014 related to our Cibolo Canyons project near San Antonio. In 2015, we collected $14,751,000 in reimbursements that were previously submitted to these districts. At year-end 2015, our inception to-date submitted and approved reimbursements for the Cibolo Canyons project were $54,376,000, of which we have collected $34,703,000. These costs are principally for water, sewer and other infrastructure assets that we have incurred and submitted or will submit to utility or improvement districts for approval and reimbursement. We expect to be reimbursed by utility and improvement districts when these districts achieve adequate tax basis or otherwise have funds available to support payment.
In 2014, we received $50,550,000 from Cibolo Canyons special improvement district (CCSID) under 2007 economic development agreements (EDA) related to development of the JW Marriott® Hill Country Resort & Spa (Resort) at our Cibolo Canyons project near San Antonio, of which $46,500,000 was related to CCSID's issuance of $48,900,000 Hotel Occupancy Tax (HOT) and Sales and Use Tax Revenue Bonds. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied on the Resort by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the

69


earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with San Antonio Real Estate (SARE), owner of the Resort, to assign SARE’s senior rights under the EDA to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable to SARE. The surety bond will decrease and gain will be recognized as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. All future receipts are expected to be recognized as gain in the period collected. We recorded gains of $1,160,000 associated with reduction of surety bond and $425,000 associated with collections from CCSID in 2015. In 2014, we recognized a gain of $6,577,000 associated with bond proceeds after recovery of our full resort investment of $24,067,000, which was included in entitled, developed and under development projects. The surety bond has a balance of $7,850,000 at year-end 2015.
In 2015, we sold Midtown Cedar Hill, a 354-unit multifamily property we developed in Cedar, Hill, Texas for $42,880,000, generating segment earnings of $9,265,000 and $18,473,000 in net proceeds after repaying $24,166,000 in outstanding debt.
In 2014, we acquired full ownership in CJUF III, RH Holdings LP partnership (the Eleven venture), owner of a 257-unit multifamily project in Austin in which we previously held a 25 percent interest, for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000. We accounted for this transaction as a business combination achieved in stages and as a result, we remeasured our equity method investment in the Eleven venture to its acquisition-date fair value of $9,839,000 and recognized the resulting gain of $7,610,000 in real estate segment earnings. At acquisition, we recorded additions to commercial and income producing properties of $53,917,000 and other assets of $992,000 primarily consisting of the estimated fair value of in-place tenant leases of $865,000. In addition, we recorded a working capital deficit of $979,000 and debt of $23,936,000.
As a general contractor on guaranteed maximum price contracts associated with two multifamily venture properties, we recognized charges of $1,543,000 in 2015, $5,111,000 in 2014 and $554,000 in 2013 related to cost overruns.
Depreciation expense related to commercial and income producing properties was $6,810,000 in 2015, $3,319,000 in 2014 and $2,507,000 in 2013 and is included in other operating expense.

Note 5 — Oil and Gas Properties and Equipment, net
Net capitalized costs, utilizing the successful efforts method of accounting, related to our oil and gas producing activities are as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Unproved leasehold interests
$
19,441

 
$
90,446

Proved oil and gas properties
119,414

 
221,299

Total costs
138,855

 
311,745

Less accumulated depreciation, depletion and amortization
(58,242
)
 
(48,252
)
 
$
80,613

 
$
263,493

We review unproved oil and gas properties for impairment based on our current exploration plans and proved oil and gas properties by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.
In 2015, we recognized $164,831,000 in non-cash impairment charges of which $107,140,000 related to our proved properties and $57,691,000 on our unproved leasehold interests principally due to a significant decline in oil prices, drilling results, a change in our plans to develop acreage and increased likelihood that non-core oil and gas assets will be sold. In 2014, we recognized $32,665,000 in non-cash impairment charges of which $17,130,000 related to our unproved leasehold interests and $15,535,000 on our proved properties principally due to the significant decline in oil prices, drilling results, a change in our plans to develop acreage and increased likelihood that non-core oil and gas assets will be sold. Impairment charges are included in cost of oil and gas producing activities on our consolidated statements of income (loss) and comprehensive income (loss).
In 2015, we recorded a net loss of $706,000 on the sale of 109,000 net mineral acres leased from others and the disposition of 39 gross (7 net) producing oil and gas wells in Nebraska, Texas, Colorado, North Dakota and Oklahoma for total sales proceeds of $17,800,000.

70


Note 6 — Investment in Unconsolidated Ventures
At year-end 2015, we had ownership interests in 20 ventures that we account for using the equity method.
Combined summarized balance sheet information for our ventures accounted for using the equity method follows:
 
Venture Assets
 
Venture Borrowings (a)
 
Venture Equity
 
Our Investment
 
At Year-End
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
242, LLC (b)
$
26,687

 
$
33,021

 
$
—

 
$
6,940

 
$
24,877

 
$
21,789

 
$
11,766

 
$
10,098

CL Ashton Woods, LP (d)
7,654

 
13,269

 
—

 
—

 
6,084

 
11,453

 
3,615

 
6,015

CL Realty, LLC
7,872

 
7,960

 
—

 
—

 
7,662

 
7,738

 
3,831

 
3,869

CREA FMF Nashville LLC (b)
58,002

 
40,014

 
51,028

 
29,660

 
4,291

 
5,987

 
3,820

 
5,516

Elan 99, LLC
34,327

 
10,070

 
14,721

 
1

 
15,838

 
9,643

 
14,255

 
8,679

FMF Littleton LLC
52,528

 
26,953

 
22,499

 
—

 
24,370

 
24,435

 
6,270

 
6,287

FMF Peakview LLC
48,908

 
43,638

 
30,524

 
23,070

 
16,828

 
17,464

 
3,447

 
3,575

FOR/SR Forsyth LLC
6,500

 
—

 
—

 
—

 
6,500

 
—

 
5,850

 
—

HM Stonewall Estates, Ltd. (d)
2,842

 
3,750

 
—

 
669

 
2,842

 
3,081

 
1,294

 
1,752

LM Land Holdings, LP (d)
32,008

 
25,561

 
7,752

 
4,448

 
22,751

 
18,500

 
9,664

 
9,322

MRECV DT Holdings LLC
4,215

 
—

 
—

 
—

 
4,215

 
—

 
3,807

 
—

MRECV Edelweiss LLC
2,237

 
—

 
—

 
—

 
2,237

 
—

 
2,029

 
—

MRECV Juniper Ridge
3,006

 
—

 
—

 
—

 
3,006

 
—

 
2,730

 
—

MRECV Meadow Crossing II LLC
728

 
—

 
—

 
—

 
728

 
—

 
655

 
—

Miramonte Boulder Pass, LLC
12,627

 
—

 
5,869

 
—

 
5,474

 
—

 
5,349

 
—

PSW Communities, LP
—

 
16,045

 
—

 
10,515

 
—

 
4,415

 
—

 
3,924

TEMCO Associates, LLC
5,284

 
11,756

 
—

 
—

 
5,113

 
11,556

 
2,557

 
5,778

Other ventures (e)
4,201

 
8,453

 
2,269

 
26,944

 
1,922

 
(25,614
)
 
1,514

 
190

 
$
309,626

 
$
240,490

 
$
134,662

 
$
102,247

 
$
154,738

 
$
110,447

 
$
82,453

 
$
65,005


Combined summarized income statement information for our ventures accounted for using the equity method follows:
 
Revenues
 
Earnings (Loss)
 
Our Share of Earnings (Loss)
 
For the Year
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
(In thousands)
242, LLC (b)
$
20,995

 
$
5,612

 
$
6,269

 
$
9,588

 
$
2,951

 
$
1,512

 
$
4,919

 
$
1,514

 
$
805

CJUF III, RH Holdings (c)
—

 
2,168

 
120

 
—

 
(956
)
 
(652
)
 
—

 
(956
)
 
(652
)
CL Ashton Woods, LP (d)
9,820

 
5,431

 
9,018

 
3,881

 
1,748

 
2,660

 
5,000

 
2,471

 
4,169

CL Realty, LLC
856

 
1,573

 
1,603

 
424

 
1,068

 
1,028

 
212

 
534

 
514

CREA FMF Nashville LLC (b)
1,227

 
—

 
—

 
(1,696
)
 
(163
)
 
—

 
(1,696
)
 
(163
)
 
—

Elan 99, LLC
—

 
—

 
—

 
(49
)
 
(87
)
 
—

 
(44
)
 
(78
)
 
—

FMF Littleton LLC
120

 
—

 
—

 
(367
)
 
(239
)
 
—

 
(92
)
 
(60
)
 
—

FMF Peakview LLC
2,057

 
4

 
1

 
(1,116
)
 
(410
)
 
(252
)
 
(223
)
 
(83
)
 
(50
)
FOR/SR Forsyth LLC
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

HM Stonewall Estates, Ltd. (d)
3,990

 
1,728

 
2,922

 
1,881

 
613

 
1,082

 
952

 
248

 
452

LM Land Holdings, LP (d)
10,956

 
21,980

 
25,426

 
8,251

 
15,520

 
11,012

 
3,342

 
4,827

 
3,418

MRECV DT Holdings LLC
—

 
—

 
—

 
167

 
—

 
—

 
—

 
—

 
—

MRECV Edelweiss LLC
—

 
—

 
—

 
151

 
—

 
—

 
137

 
—

 
—

MRECV Juniper Ridge
—

 
—

 
—

 
106

 
—

 
—

 
—

 
—

 
—

Miramonte Boulder Pass, LLC
—

 
—

 
—

 
(250
)
 
—

 
—

 
(125
)
 
—

 
—

PSW Communities, LP
29,986

 
—

 
—

 
2,688

 
(86
)
 
—

 
1,169

 
(76
)
 
—

TEMCO Associates, LLC
9,485

 
2,155

 
630

 
2,358

 
494

 
96

 
1,179

 
247

 
48

Other ventures
36,237

 
1,792

 
5,994

 
33,303

 
4,835

 
176

 
1,278

 
260

 
33

 
$
125,729

 
$
42,443

 
$
51,983

 
$
59,320

 
$
25,288

 
$
16,662

 
$
16,008

 
$
8,685

 
$
8,737


71


_____________________
(a) 
Total includes current maturities of $39,590,000 at year-end 2015, of which $6,798,000 is non-recourse to us, and $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us.
(b) 
Includes unamortized deferred gains on real estate contributed by us to ventures. We recognize deferred gains as income as real estate is sold to third parties. Deferred gains of $1,496,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2015.
(c) 
In 2014, we acquired full ownership in the Eleven venture for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000.
(d) 
Includes unrecognized basis difference of $34,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2015. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.
(e) 
Our investment in other ventures reflects our ownership interests generally ranging from 40 to 75 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.
In 2015, we invested $26,349,000 in these ventures and received $24,909,000 in distributions; in 2014, we invested $14,692,000 in these ventures and received $7,518,000 in distributions; and in 2013, we invested $857,000 in these ventures and received $9,854,000 in distributions. Distributions include both return of investments and distributions of earnings.
We provide construction and development services for some of these ventures for which we receive fees. Fees for these services were $1,856,000 in 2015, $2,275,000 in 2014 and $1,068,000 in 2013 and are included in real estate revenues.


72


Note 7 — Receivables
Receivables consist of:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Funds held by qualified intermediary for potential 1031 like-kind exchange
$
14,703

 
$
—

Oil and gas revenue accruals
3,745

 
7,293

Other receivables and accrued interest
2,448

 
6,505

Other loans secured by real estate, average interest rate of 11.31% at year-end 2015 and 4.41% at year-end 2014
2,130

 
1,737

Oil and gas joint interest billing receivables
867

 
5,738

Loan secured by real estate
—

 
3,574

 
23,893

 
24,847

Allowance for bad debts
(237
)
 
(258
)
 
$
23,656

 
$
24,589

In 2015, funds held by qualified intermediary are related to proceeds received from selling 6,915 acres of undeveloped land pending completion of a potential like-kind exchange.
In 2011, we acquired a non-performing loan that was secured by a lien on developed and undeveloped real estate located near Houston designated for single-family residential and commercial development. In 2015, the loan was paid in full and we received principal payments of $4,394,000 and interest payments of $49,000.
Estimated accretable yield is as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Beginning of year
$
839

 
$
8,908

Change in accretable yield due to change in timing of estimated cash flows
30

 
(166
)
Interest income recognized
(869
)
 
(7,903
)
 
$
—

 
$
839

Other loans secured by real estate generally are secured by a deed of trust and due within three years.

Note 8 — Debt
Debt consists of:
 
At Year-End
 
2015
 
2014
 
(In thousands)
8.50% senior secured notes due 2022
230,560

 
250,000

3.75% convertible senior notes due 2020, net of discount
106,762

 
103,194

6.00% tangible equity units, net of discount
8,768

 
17,154

Secured promissory notes — average interest rates of 3.42% at year-end 2015 and 3.17% at year-end 2014
15,400

 
15,400

Other indebtedness due through 2018 at variable and fixed interest rates ranging from 2.19% to 5.50%
28,292

 
46,996

 
$
389,782

 
$
432,744

At year-end 2015, our senior secured credit facility provides for a $300,000,000 revolving line of credit maturing May 15, 2017. The revolving line of credit may be prepaid at any time without penalty. The revolving line of credit includes a $100,000,000 sublimit for letters of credit, of which $15,899,000 is outstanding at year-end 2015. Total borrowings under our senior secured credit facility (including the face amount of letters of credit) may not exceed a borrowing base formula. At year-end 2015, we had $284,101,000 in net unused borrowing capacity under our senior credit facility.
Under the terms of our senior secured credit facility, at our option, we can borrow at LIBOR plus 4.0 percent or at the alternate base rate plus 3.0 percent. The alternate base rate is the highest of (i) KeyBank National Association’s base rate, (ii) the federal funds effective rate plus 0.5 percent or (iii) 30 day LIBOR plus 1 percent. Borrowings under the senior secured credit facility are or may be secured by (a) mortgages on the timberland, high value timberland and portions of raw entitled

73


land, as well as pledges of other rights including certain oil and gas operating properties, (b) assignments of current and future leases, rents and contracts, (c) a security interest in our primary operating account, (d) a pledge of the equity interests in current and future material operating subsidiaries and most of our majority-owned joint venture interests, or if such pledge is not permitted, a pledge of the right to distributions from such entities, and (e) a pledge of certain reimbursements payable to us from special improvement district tax collections in connection with our Cibolo Canyons project. The senior secured credit facility provides for releases of real estate and other collateral provided that borrowing base compliance is maintained.
Our debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. In third quarter 2015, we received a waiver of the consolidated tangible net worth maintenance covenant requirement of our senior credit facility. At year-end 2015, our tangible net worth requirement was $379,044,000 plus 85 percent of the aggregate net proceeds received by us from any equity offering, plus 75 percent of all positive net income, on a cumulative basis. At year-end 2015, there were no adjustments to the tangible net worth requirement for net proceeds from equity offerings or positive net income on a cumulative basis. The tangible net worth requirement is recalculated on a quarterly basis.
On December 30, 2015, we amended our senior secured credit facility to reduce the interest coverage ratio from 2.50:1.0 to 2.25:1.0 for the quarters ending December 31, 2015 and March 31, 2016. Thereafter, the interest coverage ratio returns to 2.50:1.0. At year-end 2015, we were in compliance with the financial covenants of these agreements.
We may elect to make distributions to stockholders so long as the total leverage ratio is less than 40 percent, the interest coverage ratio is greater than 3.0:1.0 and available liquidity is not less than $125,000,000. Effective December 30, 2015, the senior secured credit facility was amended to provide that we may make distributions in an aggregate amount not to exceed $50,000,000 to be funded from up to 65% of the net proceeds from sales of multifamily properties and non-core assets, such as the Radisson Hotel & Suites in Austin, and any oil and gas properties. The amendment provides us the flexibility to repurchase stock or pay a special dividend should our Board of Directors determine that we should do so, though no such decisions have been made at this time.
In 2014, we issued $250,000,000 aggregate principal of 8.50% Senior Secured Notes due 2022 (Notes). The Notes will mature on June 1, 2022 and interest on the Notes is payable semiannually at a rate of 8.5 percent per annum in arrears. Net proceeds from issuance of the Notes were used to repay our $200,000,000 senior secured term loan. In December 2015, we purchased $19,440,000 principal amount of Notes at 97% of face value, resulting in a gain of $589,000 on the early extinguishment of the retired Notes, offset by the write-off of unamortized debt issuance costs of $506,000 allocated to the retired Notes.
In 2013, we issued $125,000,000 aggregate principal amount of 3.75% convertible senior notes due 2020 (Convertible Notes). Interest on the Convertible Notes is payable semiannually at a rate of 3.75 percent per annum and they mature on March 1, 2020. The Convertible Notes have an initial conversion rate of 40.8351 per $1,000 principal amount. The initial conversion rate is subject to adjustment upon the occurrence of certain events. Prior to November 1, 2019, the Convertible Notes are convertible only upon certain circumstances, and thereafter are convertible at any time prior to the close of business on the second scheduled trading day prior to maturity. If converted, holders will receive cash, shares of our common stock or a combination thereof at our election. We intend to settle the principal amount of the Convertible Notes in cash upon conversion, with any excess conversion value to be settled in shares of our common stock. At year-end 2015, unamortized debt discount of our Convertible Notes was $18,238,000.
In 2013, we issued $150,000,000 aggregate principal amount of 6.00% tangible equity units (Units). The total offering was 6,000,000 Units, including 600,000 exercised by the underwriters, each with a stated amount of $25.00. Each Unit is comprised of (i) a prepaid stock purchase contract to be settled by delivery of a number of shares of our common stock, par value $1.00 per share to be determined pursuant to a purchase contract agreement, and (ii) a senior amortizing note due December 15, 2016 that has an initial principal amount of $4.2522, bears interest at a rate of 4.50% per annum and has a final installment payment date of December 15, 2016. The actual number of shares we may issue upon settlement of the stock purchase contract will be between 6,547,800 shares (the minimum settlement rate) and 7,857,000 shares (the maximum settlement rate) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.
At year-end 2015, secured promissory notes include a $15,400,000 loan collateralized by a 413 guest room hotel located in Austin with a carrying value of $33,621,000.
At year-end 2015, other indebtedness principally include a senior secured construction loan for one multifamily property for $23,936,000 related to a 257-unit multifamily project in Austin with a carrying value of $51,035,000 at year-end 2015. The decrease in other indebtedness is principally related to the sale of Midtown Cedar Hill and the payoff of the related debt of $24,166,000.

74


At year-end 2015 and 2014, we have $11,034,000 and $15,168,000 in unamortized deferred fees which are included in other assets. Amortization of deferred financing fees was $4,002,000 in 2015, $3,845,000 in 2014 and $3,050,000 in 2013 and is included in interest expense.
Debt maturities during the next five years are: 2016 — $27,973,000; 2017 — $551,000; 2018 — $23,936,000; 2019 — $0; 2020 — $106,762,000 and thereafter — $230,560,000.

Note 9 — Fair Value
Fair value is the exchange price that would be the amount received for an asset or paid to transfer a liability in an orderly transaction between market participants. In arriving at a fair value measurement, we use a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable. The three levels of inputs used to establish fair value are the following:
•
Level 1 — Quoted prices in active markets for identical assets or liabilities;
•
Level 2 — Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and
•
Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
We elected not to use the fair value option for cash and cash equivalents, accounts receivable, other current assets, variable debt, accounts payable and other current liabilities. The carrying amounts of these financial instruments approximate their fair values due to their short-term nature or variable interest rates. We determine the fair value of fixed rate financial instruments using quoted prices for similar instruments in active markets.
Information about our fixed rate financial instruments not measured at fair value follows:
 
Year-End 2015
 
Year-End 2014
 
 
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
Valuation
Technique
 
(In thousands)
Recurring Fair Value Measurements:
 
 
 
 
 
 
 
 
 
Loan secured by real estate
$
—

 
$
—

 
$
3,574

 
$
4,859

 
Level 2
Fixed rate debt
$
(346,090
)
 
$
(321,653
)
 
$
(370,348
)
 
$
(359,131
)
 
Level 2
Non-financial assets measured at fair value on a non-recurring basis principally include real estate assets, proved oil and gas properties, goodwill and intangible assets, which are measured for impairment.
In 2015, we recognized proved properties oil and gas non-cash impairment charges of $107,140,000 primarily in North Dakota, Nebraska and Kansas principally due to a significant decline in oil and gas prices and the likelihood these assets will be sold. The fair value of these properties was determined using Level 3 inputs and income valuation method based on estimated future commodity prices and our various operational assumptions. In instances where a third party bid was received for a combination of proved and unproved properties, an estimate of the allocation of bid prices was performed and fair value was adjusted accordingly. Included in proved oil and gas non-cash impairments were impairments associated with properties that were sold in fourth quarter 2015. In addition, in 2015 we recognized impairments of $57,691,000 for unproved leasehold interests as a result of continued decline in oil prices and our current plans to only allocate capital to these non-core assets to preserve values and optionality for ultimate sale. Fair value of certain unproved leasehold interests that were impaired were based on market comparables or where a third party bid was received for a combination of proved and unproved properties, an estimate of the allocation of fair value was performed which reduced the carrying value of these leasehold interests.
In 2015 and 2014, certain real estate assets were remeasured and reported at fair value due to events or circumstances that indicated the carrying value may not be recoverable. We determined estimated fair value based on the present value of future probability weighted cash flows expected from the sale of the long-lived asset or based on a third party appraisal of current value. As a result, we recognized non-cash asset impairment charges of $1,044,000 in 2015 associated with a residential development with golf course and country club property near Fort Worth which was sold in April 2015, one owned project near Atlanta where the remaining lots were sold in August 2015 and one owned entitled project in Atlanta. We had $399,000 non-cash impairment charges in 2014 associated with two owned entitled projects.

75


 
Year-End 2015
 
Year-End 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Non-recurring Fair Value Measurements:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved oil and gas properties
$
—

 
$
—

 
$
39,000

 
$
39,000

 
$
—

 
$
—

 
$
3,655

 
$
3,655

Unproved leasehold interests
$
—

 
$
—

 
$
18,219

 
$
18,219

 
$
—

 
$
—

 
$
—

 
$
—

Real estate
$
—

 
$
—

 
$
641

 
$
641

 
$
—

 
$
—

 
$
970

 
$
970


Note 10 — Capital Stock
In 2015, we accelerated the expiration date of our shareholder rights plan from December 11, 2017 to March 13, 2015, resulting in termination of the plan.
Please read Note 8 — Debt and Note 11 — Net Income (Loss) per Share for information about shares of common stock that could be issued under our 3.75% convertible senior notes due 2020 and our 6.00% tangible equity units.
Please read Note 17 — Share-Based and Long-Term Incentive Compensation for information about additional shares of common stock that could be issued under terms of our share-based compensation plans.
At year-end 2015, personnel of former affiliates held options to purchase 500,798 shares of our common stock. The options have a weighted average exercise price of $28.62 and a weighted average remaining contractual term of one year. At year-end 2015, the options have an aggregate intrinsic value of $0.
In 2015, we did not repurchase shares of our common stock. In 2014, we repurchased 1,491,187 shares of our common stock for $24,595,000. We have repurchased 3,493,332 shares of our common stock for $54,159,000 since we announced our 2009 strategic initiative of repurchasing up to 20 percent or up to 7,000,000 shares of our common stock.

Note 11 — Net Income (Loss) per Share
Basic and diluted earnings (loss) per share are computed using the two-class method. The two-class method is an earnings allocation formula that determines net income per share for each class of common stock and participating security. We have determined that our 6.00% tangible equity units are participating securities. Per share amounts are computed by dividing earnings available to common shareholders by the weighted average shares outstanding during each period.

76


The computations of basic and diluted earnings (loss) per share are as follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Numerator:
 
 
 
 
 
Consolidated net income (loss)
$
(212,371
)
 
$
17,088

 
$
35,061

Less: Net (income) attributable to noncontrolling interest
(676
)
 
(505
)
 
(5,740
)
Income (loss) available for diluted earnings per share
$
(213,047
)
 
$
16,583

 
$
29,321

Less: Undistributed net income allocated to participating securities
—

 
(3,018
)
 
(585
)
Income (loss) available to common shareholders for basic earnings per share
$
(213,047
)
 
$
13,565

 
$
28,736

 
 
 
 
 
 
Denominator:
 
 
 
 
 
Weighted average common shares outstanding — basic
34,266

 
35,317

 
35,365

Weighted average common shares upon conversion of participating securities (a)
—

 
7,857

 
835

Dilutive effect of stock options, restricted stock and equity-settled awards
—

 
422

 
613

Total weighted average shares outstanding — diluted
34,266

 
43,596

 
36,813

Anti-dilutive awards excluded from diluted weighted average shares outstanding
10,864

 
2,238

 
1,803

 _____________________
(a)
Our earnings per share calculation reflects the weighted average shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units, issued in 2013.
The actual number of shares we may issue upon settlement of the stock purchase contract will be between 6,547,800 shares (the minimum settlement rate) and 7,857,000 shares (the maximum settlement rate) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.
We intend to settle the principal amount of the Convertible Notes in cash upon conversion with any excess conversion value to be settled in shares of our common stock. Therefore, only the amount in excess of the par value of the Convertible Notes will be included in our calculation of diluted net income per share using the treasury stock method. As such, the Convertible Notes have no impact on diluted net income per share until the price of our common stock exceeds the conversion price of the Convertible Notes of $24.49. The average price of our common stock in 2015 did not exceed the conversion price which resulted in no additional diluted outstanding shares.

Note 12 — Income Taxes
Income tax (expense) benefit consists of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Current tax provision:
 
 
 
 
 
U.S. Federal
$
8,579

 
$
(5,444
)
 
$
(6,004
)
State and other
47

 
(1,569
)
 
(2,066
)
 
8,626

 
(7,013
)
 
(8,070
)
Deferred tax provision:
 
 
 
 
 
U.S. Federal
(38,366
)
 
(2,772
)
 
1,148

State and other
(2,895
)
 
1,128

 
(286
)
 
(41,261
)
 
(1,644
)
 
862

Income tax (expense) benefit
$
(32,635
)
 
$
(8,657
)
 
$
(7,208
)

77


A reconciliation of the federal statutory rate to the effective income tax rate on continuing operations follows:
 
For the Year
 
2015
 
2014
 
2013
Federal statutory rate (benefit)
(35
%)
 
35
 %
 
35
 %
State, net of federal benefit
(1
)
 
1

 
4

Valuation allowance
54

 
—

 
—

Recognition of previously unrecognized tax benefits
—

 
—

 
(15
)
Noncontrolling interests
—

 
—

 
(5
)
Goodwill
—

 
1

 
—

Charitable contributions
—

 
(1
)
 
—

Oil and gas percentage depletion
—

 
(2
)
 
(2
)
Effective tax rate
18
 %
 
34
 %
 
17
 %
Our 2015 effective tax rate includes a 54 percent detriment from a valuation allowance recorded against our deferred tax asset and our 2013 effective tax rate includes a 15 percent benefit from recognition of $6,326,000 of previously unrecognized tax benefits upon lapse of the statute of limitations for a previously reserved tax position.
Significant components of deferred taxes are:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Deferred Tax Assets:
 
 
 
Real estate
$
69,594

 
$
79,244

Employee benefits
15,752

 
17,352

Net operating loss carryforwards
13,827

 
3,012

Oil and gas properties
5,510

 
—

AMT credits
3,620

 
—

Income producing properties
—

 
364

Oil and gas percentage depletion carryforwards
3,616

 
3,471

Accruals not deductible until paid
911

 
1,111

Other assets
139

 
—

Gross deferred tax assets
112,969

 
104,554

Valuation allowance
(97,068
)
 
(384
)
Deferred tax asset net of valuation allowance
15,901

 
104,170

Deferred Tax Liabilities:
 
 
 
Oil and gas properties
—

 
(49,905
)
Undeveloped land
(7,588
)
 
(4,937
)
Convertible debt
(6,516
)
 
(7,816
)
Income producing properties
(2,257
)
 
—

Timber
(577
)
 
(888
)
Gross deferred tax liabilities
(16,938
)
 
(63,546
)
Net Deferred Tax Asset (Liability)
$
(1,037
)
 
$
40,624

At year-end 2015, we had approximately $37,500,000 and $43,900,000 of federal and state net operating loss carryforwards. Approximately $7,500,000 of the federal and $2,400,000 of the state net operating loss carryforwards were from our acquisition of Credo at third quarter 2012 and are subject to certain limitations. If not utilized, the federal carryforwards will expire in 2035 and the state carryforwards will expire in 2016 to 2035. We had approximately $9,800,000 of oil and gas percentage depletion carryforwards of which approximately $9,200,000 were a result of our acquisition of Credo and are subject to certain limitations. The percentage depletion and AMT credit carryforwards do not expire.
Our deferred tax asset on oil and gas properties includes the effect of impairments recorded in 2015.
Goodwill associated with our acquistion of Credo is not deductible for income tax purposes.
The increase in valuation allowance for the year 2015 was principally due to oil and gas impairments. In determining our valuation allowance, we assessed available positive and negative evidence to estimate whether sufficient future taxable income would be generated to permit use of the existing deferred tax asset. A significant piece of objective evidence was the cumulative loss incurred over the three-year period ended December 31, 2015, principally driven by impairments of oil and gas properties. Such evidence limited our ability to consider other subjective evidence, such as our projected future taxable income.

78


The amount of deferred tax asset considered realizable could be adjusted if negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence, such as our projected future taxable income.
We file income tax returns in the U.S. federal jurisdiction and in various state jurisdictions. We are no longer subject to U.S. federal income tax examinations for years before 2012 and state examinations for years before 2011.
A reconciliation of the beginning and ending amount of tax benefits not recognized for book purposes is as follows:
 
At Year-End
 
2015
 
2014
 
2013
 
(In thousands)
Balance at beginning of year
$
—

 
$
—

 
$
5,831

Reductions for tax positions of prior years
—

 
—

 
—

Reductions due to lapse of statute of limitations
—

 
—

 
(5,831
)
Balance at end of year that would affect the annual effective tax rate if recognized
$
—

 
$
—

 
$
—

We recognize interest accrued related to unrecognized tax benefits in income tax expense. In 2015, 2014 and 2013, we recognized approximately $0, $0 and $75,000 in interest expense. At year-end 2015 and 2014, we have no accrued interest or penalties.

Note 13 — Litigation and Environmental Contingencies
Litigation
We are involved in various legal proceedings that arise from time to time in the ordinary course of doing business and believe that adequate reserves have been established for any probable losses. We do not believe that the outcome of any of these proceedings should have a significant adverse effect on our financial position, long-term results of operations or cash flows. It is possible, however, that charges related to these matters could be significant to our results or cash flows in any one accounting period.
On October 4, 2014, James Huffman, a former director and CEO of CREDO Petroleum Corporation (Credo), which we acquired in 2012 and is now known as Forestar Petroleum Corporation, filed Huffman vs. Forestar Petroleum Corporation, Case Number 14CV33811, Civil Division, District Court for the City and County of Denver, Colorado. Prior to his retirement from Credo, Huffman participated in an employee compensation program under which he received overriding royalty interests (ORRI) in certain leases or wells in which Credo had an interest. Huffman claims entitlement to ORRI on nearly all North Dakota leases, none of which were assigned by Credo to Huffman prior to his retirement, and to ORRI on several Kansas and Nebraska leases. Huffman is seeking to have ORRI assigned to him. We believe Huffman’s claims are without merit and are vigorously defending the case. We are unable to estimate a possible loss or range of possible loss for this matter because of, among other factors, (i) significant unresolved questions of fact, including the time period covered by Huffman’s claims, (ii) discovery remaining to be conducted by both parties; (iii) impact of our counterclaims against Huffman, and (iv) any other factors that may have a material effect on the litigation.
Environmental
Environmental remediation liabilities arise from time to time in the ordinary course of doing business, and we believe we have established adequate reserves for any probable losses that we can reasonably estimate. We own 288 acres near Antioch, California, portions of which were sites of a former paper manufacturing operation that are in remediation. We have received certificates of completion on all but one 80 acre tract, a portion of which includes subsurface contamination. In 2015, we increased our reserves for environmental remediation by $689,000 due to additional testing and remediation requirements by state regulatory agencies. At year-end 2015, our accrued liability to complete remediation activities was $682,000, which is included in other accrued expenses. It is possible that remediation or monitoring activities could be required in addition to those included within our estimate, but we are unable to determine the scope, timing or extent of such activities.
We have asset retirement obligations related to the abandonment and site restoration requirements that result from the acquisition, construction and development of oil and gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income (loss) and comprehensive income (loss). At year-end 2015, our asset retirement obligation was $1,758,000, which is included in other liabilities.


79


Note 14 — Commitments and Other Contingencies
We lease facilities and equipment under non-cancelable long-term operating lease agreements. In addition, we have various obligations under other office space and equipment leases of less than one year. Rent expense on facilities and equipment was $3,872,000 in 2015, $2,617,000 in 2014 and $2,374,000 in 2013. Future minimum rental commitments under non-cancelable operating leases having a remaining term in excess of one year are: 2016 — $2,696,000; 2017 — $2,738,000; 2018 — $1,706,000; 2019 — $170,000; 2020 — $174,000 and thereafter —$59,000.
We have two years remaining on groundwater leases of about 20,000 acres. At year-end 2015, the remaining contractual obligation for these groundwater leases is $1,009,000.
We lease approximately 32,000 square feet of office space in Austin, Texas, which we occupy as our corporate headquarters. The remaining contractual obligation for this lease is $4,212,000. We also lease office space in several other locations in support of our business operations with approximately 21,000 square feet in Denver, Colorado. The total remaining contractual obligations for these leases is $2,269,000.
We may provide performance bonds and letters of credit on behalf of certain ventures that would be drawn on due to failure to satisfy construction obligations as general contractor or for failure to timely deliver streets and utilities in accordance with local codes and ordinances.

Unallocated Severance-related Costs
In connection with the departures of our former CEO and CFO in September 2015, we recorded severance-related charges of $3,314,000 which are included in general and administrative expense on our consolidated statements of income (loss) and comprehensive income (loss). We paid $2,732,000 of these severance-related charges in fourth quarter 2015 with the balance to be paid in 2016.

Oil and Gas Restructuring Costs
In connection with review of strategic alternatives with respect to our oil and gas business and the determination it is a non-core business that we will be exiting over time, we offered retention bonuses to key personnel provided they remained our employees through December 2015. We expensed retention bonus costs over the retention period. In 2015, we incurred severance expenses related to staff reductions, paid a portion of the 2014 accrual under written severance agreements and incurred costs associated with closure of our Fort Worth office. Office closure costs include a $1,750,000 lease termination charge and $391,000 for write off of leasehold improvements which were partially offset by a deferred lease credit of $364,000. These restructuring costs are included in other operating expense on our consolidated statements of income (loss) and comprehensive income (loss). We may incur additional costs related to our initiatives to exit non-core oil and gas assets.
The following table summarizes activity related to liabilities associated with our oil and gas restructuring activities in 2015:
 
Employee-Related Costs
 
Lease Termination Charge
 
Total
 
(In thousands)
Balance at year-end 2014
$
(2,367
)
 
$
—

 
$
(2,367
)
Additions
(2,047
)
 
(1,750
)
 
(3,797
)
Payments
3,365

 
1,750

 
5,115

Balance at year-end 2015
$
(1,049
)
 
$
—

 
$
(1,049
)




80


Note 15 — Segment Information
We manage our operations through three business segments: real estate, oil and gas and other natural resources. Real estate secures entitlements and develops infrastructure on our lands for single-family residential and mixed-use communities, and manages our undeveloped land, commercial and income producing properties, primarily a hotel and our multifamily properties. Oil and gas is an independent oil and gas exploration, development and production operation and manages our owned and leased mineral interests. Other natural resources manages our timber, recreational leases and water resource initiatives.
We evaluate performance based on segment earnings (loss) before unallocated items and income taxes. Segment earnings (loss) consist of operating income, equity in earnings (loss) of unconsolidated ventures, gain on sales of assets, interest income on loans secured by real estate and net (income) loss attributable to noncontrolling interests. Items not allocated to our business segments consist of general and administrative expense, share-based and long-term incentive compensation, gain on sale of strategic timberland, interest expense and other corporate non-operating income and expense. The accounting policies of the segments are the same as those described in Note 1 — Summary of Significant Accounting Policies. Our revenues are derived from our U.S. operations and all of our assets are located in the U.S. In 2015, 2014 and 2013, no single customer accounted for more than 10 percent of our total revenues, other than the customers associated with the sale of our multifamily projects Midtown Cedar Hill and Promesa in 2015 and 2013.
 
Real
Estate
 
Oil and Gas
 
Other Natural
Resources
 
Items Not
Allocated to
Segments
 
 
Total
 
(In thousands)
For the year or at year-end 2015
 
 
 
 
 
 
 
 
 
 
Revenues
$
202,830

 
$
52,939

 
$
6,652

 
$
—

  
 
$
262,421

Depreciation, depletion and amortization
7,605

 
28,774

 
540

 
8,166

  
 
45,085

Equity in earnings of unconsolidated ventures
15,582

 
275

 
151

 
—

  
 
16,008

Income (loss) before taxes
67,678

 
(184,396
)
 
(608
)
 
(63,086
)
(a) 
 
(180,412
)
Total assets
691,406

 
144,436

 
19,106

 
125,565

  
 
980,513

Investment in unconsolidated ventures
82,453

 
—

 
—

 
—

  
 
82,453

Capital expenditures (b)
13,644

 
49,776

 
745

 
242

  
 
64,407

For the year or at year-end 2014
 
 
 
 
 
 
 
 
 
 
Revenues
$
213,112

 
$
84,300

 
$
9,362

 
$
—

  
 
$
306,774

Depreciation, depletion and amortization
3,741

 
29,442

 
497

 
8,035

  
 
41,715

Equity in earnings of unconsolidated ventures
8,068

 
586

 
31

 
—

  
 
8,685

Income (loss) before taxes
96,906

 
(22,686
)
 
5,499

 
(54,479
)
(a) 
 
25,240

Total assets
654,774

 
342,703

 
22,531

 
238,191

  
 
1,258,199

Investment in unconsolidated ventures
65,005

 
—

 
—

 
—

  
 
65,005

Capital expenditures (b)
28,980

 
103,385

 
5,817

 
616

  
 
138,798

For the year or at year-end 2013
 
 
 
 
 
 
 
 
 
 
Revenues
$
248,011

 
$
72,313

 
$
10,721

 
$
—

  
 
$
331,045

Depreciation, depletion and amortization
3,117

 
19,552

 
651

 
6,660

  
 
29,980

Equity in earnings of unconsolidated ventures
8,089

 
592

 
56

 
—

  
 
8,737

Income (loss) before taxes
68,454

 
18,859

 
6,507

 
(57,291
)
(a) 
 
36,529

Total assets
582,802

 
312,553

 
23,478

 
253,319

  
 
1,172,152

Investment in unconsolidated ventures
41,147

 
—

 
—

 
—

  
 
41,147

Capital expenditures (b)
7,265

 
97,696

 
2,720

 
216

  
 
107,897


81


 _____________________
(a) 
Items not allocated to segments consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
General and administrative expense
$
(24,802
)
 
$
(21,229
)
 
$
(20,597
)
Share-based and long-term incentive compensation expense
(4,474
)
 
(3,417
)
 
(16,809
)
Interest expense
(34,066
)
 
(30,286
)
 
(20,004
)
Other corporate non-operating income
256

 
453

 
119

 
$
(63,086
)
 
$
(54,479
)
 
$
(57,291
)
(b) 
Consists of expenditures for oil and gas properties and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.

Note 16 — Variable Interest Entities
We participate in real estate ventures for the purpose of acquiring and developing residential, multifamily and mixed-use communities in which we may or may not have a controlling financial interest. Generally accepted accounting principles require consolidation of VIEs in which an enterprise has a controlling financial interest and is the primary beneficiary. A controlling financial interest will have both of the following characteristics: (a) the power to direct the VIE activities that most significantly impact economic performance and (b) the obligation to absorb the VIE losses and right to receive benefits that are significant to the VIE. We examine specific criteria and use judgment when determining whether we are the primary beneficiary and must consolidate a VIE. We perform this review initially at the time we enter into venture agreements and continuously reassess to see if we are the primary beneficiary of a VIE.
At year-end 2015, we have two VIEs. We account for these VIEs using the equity method and we are not the primary beneficiary. Although we have certain rights regarding major decisions, we do not have the power to direct the activities that are most significant to the economic performance of these VIEs. At year-end 2015, these VIEs have total assets of $62,187,000, substantially all of which represent developed and undeveloped real estate and total liabilities of $55,989,000, which includes $2,269,000 of borrowings classified as current maturities. These amounts are included in the summarized balance sheet information for ventures accounted for using the equity method in Note 6 — Investment in Unconsolidated Ventures. At year-end 2015, our investment is $5,322,000 and is included in investment in unconsolidated ventures. In 2015, we contributed $148,000 to these VIEs. Our maximum exposure to loss related to one of these VIEs is estimated at $3,780,000, which exceeds our investment as we have a nominal general partner interest and could be held responsible for its liabilities. The maximum exposure to loss represents the maximum loss that we could be required to recognize assuming all the ventures’ assets (principally real estate) are worthless, without consideration of the probability of a loss or of any actions we may take to mitigate any such loss.
In 2014, we acquired our partner's noncontrolling interests in the Lantana partnerships for $7,971,000. Prior to acquisition of the noncontrolling interests, we were the primary beneficiary of all but one of the Lantana partnerships which were VIEs and consolidated in our financial statements. We adjusted the carrying amount of noncontrolling interests to reflect the change in our ownership interest in the partnerships. The difference between the consideration paid and the carrying amount of the noncontrolling interests acquired is recognized as an adjustment to additional paid in capital attributable to Forestar, net of deferred taxes of $1,729,000.



82


Note 17 — Share-Based and Long-Term Incentive Compensation
Share-based and long-term incentive compensation expense consists of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Cash-settled awards
$
(3,127
)
 
$
(3,710
)
 
$
7,774

Equity-settled awards
5,026

 
5,168

 
4,281

Restricted stock
(8
)
 
(25
)
 
538

Stock options
2,355

 
1,984

 
4,216

Total share-based compensation
$
4,246

 
$
3,417

 
$
16,809

Deferred cash
228

 
—

 
—

 
$
4,474

 
$
3,417

 
$
16,809

Share-based and long-term incentive compensation expense is included in:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
General and administrative
$
2,451

 
$
1,001

 
$
7,779

Other operating
2,023

 
2,416

 
9,030

 
$
4,474

 
$
3,417

 
$
16,809

Excluded from share-based compensation expense in the table above are fees earned by directors in the amount of $1,203,000 for 2015, $906,000 for 2014 and $876,000 for 2013 for which they elected to defer payment until retirement in the form of share-settled units. These expenses are included in general and administrative expense on our consolidated statements of income (loss) and comprehensive income (loss).
Share-Based Compensation
The fair value of awards granted to retirement-eligible employees and expensed at the date of grant was $517,000 in 2015, $760,000 in 2014 and $590,000 in 2013. Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options is $5,109,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years. We did not capitalize any share-based compensation in 2015, 2014 or 2013.
In 2015 and 2014, we issued 288,089 and 215,561 shares out of our treasury stock associated with vesting of stock-based awards or exercise of stock options, net of 51,521 and 55,238 shares withheld having a value of $762,000 and $1,043,000 for payroll taxes in connection with vesting of stock-based awards or exercise of stock options which are reflected in financing activities in our consolidated statements of cash flows.
A summary of awards granted under our 2007 Stock Incentive Plan follows:
Cash-settled awards
Cash-settled awards granted to our employees in the form of restricted stock units or stock appreciation rights generally vest over three to four years from the date of grant and generally provide for accelerated vesting upon death, disability or if there is a change in control. Vesting for some restricted stock unit awards is also conditioned upon achievement of a minimum one percent annualized return on assets over a three-year period. Cash-settled stock appreciation rights have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. Stock appreciation rights were granted with an exercise price equal to the market value of our stock on the date of grant.
Cash-settled awards granted to our directors in the form of restricted stock units are fully vested at the time of grant and payable upon retirement.

83


The following table summarizes the activity of cash-settled restricted stock unit awards in 2015:
 
Equivalent
Units
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
185

 
$18.49
Granted
60

 
13.26
Vested
(117
)
 
18.26
Forfeited
(11
)
 
18.83
Non-vested at end of period
117

 
16.00
The weighted average grant date fair value of cash-settled restricted stock unit awards was $18.96 per unit for 2014 and $18.70 per unit for 2013. The fair value of cash-settled restricted stock unit awards settled was $2,469,000 in 2015, $2,286,000 in 2014, and $3,780,000 in 2013. The aggregate current value of non-vested awards is $1,286,000 at year-end 2015 based on a year-end stock price of $10.94.
The following table summarizes the activity of cash-settled stock appreciation rights in 2015:
 
Rights
Outstanding
 
Weighted Average
Exercise Price
 
Weighted Average
Remaining Contractual Term
 
Aggregate Intrinsic Value
(Current Value Less Exercise Price)
 
(In thousands)
 
(Per share)
 
(In years)
 
(In thousands)
Balance at beginning of period
458

 
$12.54
 
4
 
$1,732
Granted
90

 
14.08
 
 
 
 
Exercised
(39
)
 
9.29
 
 
 
 
Forfeited
(22
)
 
15.00
 
 
 
 
Balance at end of period
487

 
12.97
 
4
 
404
Exercisable at end of period
414

 
12.77
 
3
 
404
The intrinsic value of cash-settled stock appreciation rights settled was $206,000 in 2015, $1,181,000 in 2014 and $3,458,000 in 2013.
The fair value of accrued cash-settled awards at year-end 2015 and year-end 2014 were $3,757,000 and $9,560,000 and is included in other liabilities in our consolidated balance sheets.
Equity-settled awards
Equity-settled awards granted to our employees include restricted stock units (RSU), which vest after three years from the date of grant, market-leveraged stock units (MSU), which vest after three years from date of grant and performance stock units (PSU), which generally vest after three years from the date of grant if certain performance goals are met. Equity settled awards in the form of restricted stock units granted to our directors are fully vested at time of grant and settled upon retirement. The following table summarizes the activity of equity-settled awards in 2015:
 
Equivalent
Units
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
710

 
$
19.24

Granted
395

 
12.99

Vested
(340
)
 
14.23

Forfeited
(134
)
 
18.18

Non-vested at end of period
631

 
18.25

In 2015, we granted 234,000 MSU awards. These awards will be settled in common stock based upon our stock price performance over three years from the date of grant. The number of shares to be issued could range from a high of 351,000 shares if our stock price increases by 50 percent or more, to 117,000 shares if our stock price decreases by 50 percent, or could be zero if our stock price decreases by more than 50 percent, the minimum threshold performance. We estimate the grant date

84


fair value of MSU awards using a Monte Carlo simulation pricing model and the following assumptions:
 
 
For the Year
 
 
2015
 
2014
 
2013
Expected stock price volatility
 
32.9
%
 
42.2
%
 
42.2
%
Risk-free interest rate
 
1.0
%
 
0.7
%
 
0.4
%
Expected dividend yield
 
—
%
 
—
%
 
—
%
Weighted average grant date fair value of MSU awards (per unit)
 
$
15.11

 
$
20.38

 
$
21.09

The weighted average grant date fair value of equity-settled awards (RSU, MSU, PSU) per unit in 2015, 2014 and 2013 was $12.99, $19.18 and $20.21. The fair value of equity-settled awards settled was $4,451,000, $3,119,000 and $8,000 in 2015, 2014 and 2013.
Unrecognized share-based compensation expense related to non-vested equity-settled awards is $3,258,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years.
Restricted stock awards
Restricted stock awards generally vest over three years, typically if we achieve a minimum one percent annualized return on assets over such three-year period. The following table summarizes the activity of restricted stock awards in 2015:
 
Restricted
Shares
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
17

 
$
17.56

Granted
—

 
—

Vested
(7
)
 
14.59

Forfeited
(6
)
 
19.00

Non-vested at end of period
4

 
20.55

The fair value of our restricted stock awards settled in 2015, 2014 and 2013 was $88,000, $341,000 and $3,002,000.
Unrecognized share-based compensation expense related to non-vested restricted stock awards is $14,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be one year.
Stock options
Stock options have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. In 2015 and 2013, options were granted with an exercise price equal to the market value of our stock on the date of grant. We did not grant any options in 2014. The following table summarizes the activity of stock option awards in 2015:
 
Options
Outstanding
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Term
 
Aggregate
Intrinsic Value
(Current
Value Less
Exercise Price)
 
(In thousands)
 
(Per share)
 
(In years)
 
(In thousands)
Balance at beginning of period
1,861

 
$
20.74

 
6
 
$
643

Granted
413

 
13.86

 
 
 
 
Exercised
—

 
—

 
 
 
 
Forfeited
(103
)
 
18.01

 
 
 
 
Balance at end of period
2,171

 
19.56

 
5
 
156

Exercisable at end of period
1,687

 
20.83

 
4
 
156


85


We estimate the grant date fair value of stock options that do not have a market condition using the Black-Scholes option pricing model and the following assumptions:
 
 
For the Year
 
 
2015
 
2013
Expected stock price volatility
 
45.6
%
 
66.8
%
Risk-free interest rate
 
1.8
%
 
1.4
%
Expected life of options (years)
 
6

 
6

Expected dividend yield
 
—
%
 
—
%
Weighted average grant date fair value of options (per share)
 
$
6.51

 
$
11.47

We determine the expected life using the simplified method which utilizes the midpoint between the vesting period and the contractual life of the awards. The expected stock price volatility utilizes our historical volatility for a period corresponding to the expected life of the options.
Stock option awards granted in third quarter 2015 in connection with management promotions have a ten-year term, vest ratably over three years and are exercisable only when our stock price exceeds $17.50 per share. We estimated the fair value of these options with market conditions using Monte Carlo simulation pricing model and the following assumptions:
 
 
For the Year
 
 
2015
Expected stock price volatility
 
61.4
%
Risk-free interest rate
 
2.2
%
Expected dividend yield
 
—
%
Weighted average grant date fair value of options (per share)
 
$
7.87

The fair value of vested stock options was $0 in 2015, $21,000 in 2014 and $1,355,000 in 2013. The intrinsic value of options exercised was $0 in 2015, $568,000 in 2014 and $562,000 in 2013. Unrecognized share-based compensation expense related to non-vested stock options is $1,837,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years.
Pre-Spin Awards
Certain of our employees participated in Temple-Inland’s share-based compensation plans. In conjunction with our 2007 spin-off, these awards were equitably adjusted into separate awards of the common stock of Temple-Inland and the spin-off entities.
The intrinsic value of pre-spin awards exercised was $24,000 in 2015, $352,000 in 2014 and $1,382,000 in 2013.
Pre-spin stock option awards to our employees to purchase our common stock have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. At year-end 2015, there were 44,000 pre-spin awards outstanding and exercisable on our stock with a weighted average exercise price of $28.89 and weighted average remaining term of one year.
Long-Term Incentive Compensation
In 2015, we granted $587,000 of long-term incentive compensation in the form of deferred cash compensation. Deferred cash will be paid out after the earlier of three years or the employee's retirement eligibility date and the expense is recognized ratably over the vesting period. The accrued liability was $225,000 at year-end 2015 and is included in other liabilities.

Note 18 — Retirement Plans
Our defined contribution retirement plans include a 401(k) plan, which is funded, and a supplemental plan for certain employees, which is unfunded. The expense of our defined contribution retirement plans was $1,255,000 in 2015, $1,651,000 in 2014 and $1,456,000 in 2013. The unfunded liability for our supplemental plan was $802,000 at year-end 2015 and $715,000 at year-end 2014 and is included in other liabilities.

Note 19 — Supplemental Oil and Gas Disclosures (Unaudited)
The following unaudited information regarding our oil and gas reserves has been prepared and is presented pursuant to requirements of the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB).

86


We lease our mineral interests, principally in Texas and Louisiana, to third-party entities for the exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and we retain a royalty interest and may take an additional participation in production, including a working interest in which we pay a share of the costs to drill, complete and operate a well and receive a proportionate share of the production revenues.
We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to assist in preparing estimates of our proved oil and gas reserves, all of which are located in the U.S., and future net cash flows as of year-end 2015, 2014 and 2013.
These estimates were based on the economic and operating conditions existing at year-end 2015, 2014 and 2013. Proved developed reserves are those quantities of petroleum from existing wells and facilities, which by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward for known reservoirs and under defined economic conditions, operating methods and government regulations.
SEC rules require disclosure of proved reserves using the twelve-month average beginning-of-month price (which we refer to as the average price) for the year. These same average prices also are used in calculating the amount of (and changes in) future net cash inflows related to the standardized measure of discounted future net cash flows.
For 2015, 2014 and 2013, the average spot price per barrel of oil based on the West Texas Intermediate Crude price is $50.28, $94.99 and $96.91 and the average price per MMBTU of gas based on the Henry Hub spot market is $2.59, $4.35 and $3.67. All prices were then adjusted for quality, transportation fees and regional price differentials.
The process of estimating proved reserves and future net cash flows is complex involving decisions and assumptions in evaluating the available engineering and geologic data and prices for oil and gas and the cost to produce these reserves and other factors, many of which are beyond our control. As a result, these estimates are imprecise and should be expected to change as future information becomes available. These changes could be significant. In addition, this information should not be construed as being the current fair market value of our proved reserves.


87


Estimated Quantities of Proved Oil and Gas Reserves
Estimated quantities of proved oil and gas reserves are summarized as follows:
 
Reserves
 
Oil (a)
(Barrels)
 
Gas
(Mcf)
 
(In thousands)
Consolidated entities:
 
 
 
Year-end 2012
3,220

 
11,722

Revisions of previous estimates
182

 
1,243

Extensions and discoveries
3,085

 
2,046

Acquisitions
35

 
531

Production
(698
)
 
(1,912
)
Year-end 2013
5,824

 
13,630

Revisions of previous estimates
608

 
293

Extensions and discoveries
2,191

 
774

Acquisitions
85

 
31

Sales
(105
)
 
(218
)
Production
(931
)
 
(1,861
)
Year-end 2014
7,672

 
12,649

Revisions of previous estimates
(855
)
 
(1,675
)
Extensions and discoveries
224

 
173

Acquisitions
—

 
—

Sales
(704
)
 
(1,223
)
Production
(1,158
)
 
(1,967
)
Year-end 2015
5,179

 
7,957

Our share of ventures accounted for using the equity method:
 
 
 
Year-end 2012
—

 
2,572

Revisions of previous estimates
—

 
7

Production
—

 
(247
)
Year-end 2013
—

 
2,332

Revisions of previous estimates
—

 
(382
)
Production
—

 
(199
)
Year-end 2014
—

 
1,751

Revisions of previous estimates
—

 
(320
)
Production
—

 
(168
)
Year-end 2015
—

 
1,263

Total consolidated and our share of equity method ventures:
 
 
 
Year-end 2013
 
 
 
Proved developed reserves
3,893

 
13,717

Proved undeveloped reserves
1,931

 
2,245

Total Year-end 2013
5,824

 
15,962

Year-end 2014
 
 
 
Proved developed reserves
5,269

 
12,599

Proved undeveloped reserves
2,403

 
1,801

Total Year-end 2014
7,672

 
14,400

Year-end 2015
 
 
 
Proved developed reserves
5,179

 
9,220

Proved undeveloped reserves
—

 
—

Total Year-end 2015
5,179

 
9,220

 _____________________
(a) 
Includes natural gas liquids (NGLs).


88


We do not have any estimated reserves of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas.
In 2015, oil and gas properties having reserves consisting of approximately 704,000 barrels of oil and 1,223,000 Mcf of gas located primarily in the Texas Panhandle and Bakken/Three Forks formations were sold. Due to the significant decline in oil and gas prices during 2015, net negative revisions of previous estimates were 855,000 barrels of oil and 1,995,000 Mcf of gas. At year-end 2015, we have no barrels of oil equivalent (BOE) of proved undeveloped (PUD) reserves based on our plan to exit non-core oil and gas working interest assets compared with 2,703,000 BOE of PUD reserves at year-end 2014.
In 2014, increases in extensions and discoveries of 2,191,000 barrels were primarily associated with new reserves in the Bakken/Three Forks formations. An estimated 694,000 barrels of these extensions and discoveries were associated with new producing wells while a further 913,000 barrels of proved undeveloped reserves were added during 2014. Approximately 105,000 barrels of oil and 218,000 Mcf of gas reserves located primarily in Oklahoma were sold during the year. We realized a net positive revision of previous estimates of 608,000 barrels which is primarily driven by improved drilling results in the Bakken/Three Forks formation yielding higher average estimated ultimate recoverable quantities of proved reserves per well.
In 2013, increase in gas prices accounted for about 1,243,000 Mcf of upward revisions in gas reserves for our consolidated entities.
In 2015, 2014 and 2013, reserve additions from new wells drilled and completed during the year are shown for both consolidated entities and ventures accounted for using the equity method under extensions and discoveries. There were 36 new well additions in 2015, 106 new well additions in 2014 and 88 new well additions in 2013.
Capitalized Costs Relating to Oil and Gas Producing Activities
Capitalized costs related to our oil and gas producing activities are as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Consolidated entities:
 
 
 
Unproved oil and gas properties
$
19,441

 
$
90,446

Proved oil and gas properties
119,414

 
221,299

Total costs
138,855

 
311,745

Less accumulated depreciation, depletion and amortization
(58,242
)
 
(48,252
)
 
$
80,613

 
$
263,493

We have not capitalized any costs for our share in ventures accounted for using the equity method.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities:
 
 
 
 
 
Acquisition costs
 
 
 
 
 
Proved properties
$
—

 
$
2,001

 
$
—

Unproved properties
4,832

 
25,666

 
35,806

Exploration costs
17,922

 
39,399

 
10,486

Development costs
27,609

 
40,277

 
54,538

 
$
50,363

 
$
107,343

 
$
100,830

We have not incurred any costs for our share in ventures accounted for using the equity method. In 2015, acquisition of leasehold interests, exploration expenses, and development costs have decreased as a result of our increased focus on exiting and selling our leasehold working interests.

89


Standardized Measure of Discounted Future Net Cash Flows
Estimates of future cash flows from proved oil and gas reserves are shown in the following table. Estimated income taxes are calculated by applying the appropriate tax rates to the estimated future pre-tax net cash flows less depreciation of the tax basis of properties and the statutory depletion allowance.
 
At Year-End
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities:
 
 
 
 
 
Future cash inflows
$
216,588

 
$
665,657

 
$
544,098

Future production and development costs
(93,623
)
 
(271,735
)
 
(231,801
)
Future income tax expenses
(22,218
)
 
(106,002
)
 
(77,361
)
Future net cash flows
100,747

 
287,920

 
234,936

10% annual discount for estimated timing of cash flows
(33,951
)
 
(124,079
)
 
(99,383
)
Standardized measure of discounted future net cash flows
$
66,796

 
$
163,841

 
$
135,553

Our share in ventures accounted for using the equity method:
 
 
 
 
 
Future cash inflows
$
2,283

 
$
6,186

 
$
4,765

Future production and development costs
(245
)
 
(664
)
 
(512
)
Future income tax expenses
(774
)
 
(2,098
)
 
(1,616
)
Future net cash flows
1,264

 
3,424

 
2,637

10% annual discount for estimated timing of cash flows
(562
)
 
(1,649
)
 
(1,337
)
Standardized measure of discounted future net cash flows
$
702

 
$
1,775

 
$
1,300

Total consolidated and our share of equity method ventures
$
67,498

 
$
165,616

 
$
136,853

Future net cash flows were computed using prices used in estimating proved oil and gas reserves, year-end costs, and statutory tax rates (adjusted for tax deductions) that relate to proved oil and gas reserves.


90


Changes in the standardized measure of discounted future net cash flow follows:
 
For the Year
 
Consolidated
 
Our Share of Equity
Method Ventures
 
Total
 
(In thousands)
Year-end 2012
$
106,543

 
$
1,413

 
$
107,956

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
23,422

 
415

 
23,837

Net change in future development costs
(2,897
)
 
—

 
(2,897
)
Sales of oil and gas, net of production costs
(56,559
)
 
(801
)
 
(57,360
)
Net change due to extensions and discoveries
54,539

 
—

 
54,539

Net change due to acquisition of reserves
1,160

 
—

 
1,160

Net change due to revisions of quantity estimates
8,673

 
6

 
8,679

Previously estimated development costs incurred
4,124

 
—

 
4,124

Accretion of discount
13,540

 
228

 
13,768

Net change in timing and other
(718
)
 
(31
)
 
(749
)
Net change in income taxes
(16,274
)
 
70

 
(16,204
)
Aggregate change for the year
29,010

 
(113
)
 
28,897

Year-end 2013
135,553

 
1,300

 
136,853

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
(1,064
)
 
1,571

 
507

Net change in future development costs
1,308

 
—

 
1,308

Sales of oil and gas, net of production costs
(63,192
)
 
(787
)
 
(63,979
)
Net change due to extensions and discoveries
58,228

 
—

 
58,228

Net change due to acquisition of reserves
2,778

 
—

 
2,778

Net change due to divestitures of reserves
(5,804
)
 
—

 
(5,804
)
Net change due to revisions of quantity estimates
15,303

 
(343
)
 
14,960

Previously estimated development costs incurred
15,497

 
—

 
15,497

Accretion of discount
18,067

 
210

 
18,277

Net change in timing and other
4,198

 
115

 
4,313

Net change in income taxes
(17,031
)
 
(291
)
 
(17,322
)
Aggregate change for the year
28,288

 
475

 
28,763

Year-end 2014
163,841

 
1,775

 
165,616

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
(136,536
)
 
(1,112
)
 
(137,648
)
Net change in future development costs
92

 
—

 
92

Sales of oil and gas, net of production costs
(31,732
)
 
(428
)
 
(32,160
)
Net change due to extensions and discoveries
11,747

 
—

 
11,747

Net change due to acquisition of reserves
—

 
—

 
—

Net change due to divestitures of reserves
(15,855
)
 
 
 
(15,855
)
Net change due to revisions of quantity estimates
(15,164
)
 
(267
)
 
(15,431
)
Previously estimated development costs incurred
15,096

 
—

 
15,096

Accretion of discount
22,600

 
286

 
22,886

Net change in timing and other
4,018

 
(210
)
 
3,808

Net change in income taxes
48,689

 
658

 
49,347

Aggregate change for the year
(97,045
)
 
(1,073
)
 
(98,118
)
Year-end 2015
$
66,796

 
$
702

 
$
67,498

Results of Operations for Oil and Gas Producing Activities
Our royalty interests are contractually defined and based on a percentage of production at prevailing market prices. We receive our percentage of production in cash. Similarly, for operating properties our working interests and the associated net revenue interests are contractually defined and we pay our proportionate share of the capital and operating costs to develop and operate the well and we market our share of the production. Our revenues fluctuate based on changes in the market prices for

91


oil and gas, the decline in production from existing wells, and other factors affecting oil and gas exploration and production activities, including the cost of development and production.
Information about the results of operations of our oil and gas interests follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities
 
 
 
 
 
Revenues
$
51,553

 
$
82,919

 
$
69,036

Production costs
(19,820
)
 
(19,727
)
 
(12,477
)
Exploration costs
(11,864
)
 
(17,416
)
 
(10,486
)
Depreciation, depletion, amortization
(28,774
)
 
(29,442
)
 
(19,552
)
Non-cash impairment of proved oil and gas properties and unproved leasehold interests
(164,831
)
 
(32,665
)
 
(473
)
Oil and gas administrative expenses
(11,700
)
 
(17,000
)
 
(14,407
)
Accretion expense
(144
)
 
(121
)
 
(94
)
Income tax expenses
14,717

 
13,398

 
(3,471
)
Results of operations
(170,863
)
 
(20,054
)
 
8,076

Our share in ventures accounted for using the equity method:
 
 
 
 
 
Revenues
$
428

 
$
786

 
$
801

Production costs
(102
)
 
(105
)
 
(123
)
Oil and gas administrative expenses
(51
)
 
(95
)
 
(86
)
Income tax expenses
21

 
(235
)
 
(178
)
Results of operations
$
296

 
$
351

 
$
414

Total results of operations
$
(170,567
)
 
$
(19,703
)
 
$
8,490

Production costs represent our share of oil and gas production severance taxes, and lease operating expenses. Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs.


92


Note 20 — Summary of Quarterly Results of Operations (Unaudited)
Summarized quarterly financial results for 2015 and 2014 follows:
 
First Quarter (a)
 
Second Quarter (a)
 
Third
    Quarter (a)
 
Fourth
    Quarter (a)
 
(In thousands, except per share amounts)
2015
 
 
 
 
 
 
 
Total revenues
$
47,805

 
$
57,430

 
$
43,168

 
$
114,018

Gross profit (loss)
17,289

 
(35,009
)
 
(69,572
)
 
8,341

Operating income (loss)
(7,737
)
 
(52,714
)
 
(94,751
)
 
(9,482
)
Equity in earnings of unconsolidated ventures
3,045

 
5,584

 
2,909

 
4,470

Income (loss) before taxes
(12,596
)
 
(55,062
)
 
(100,095
)
 
(11,983
)
Net income (loss) attributable to Forestar Group Inc.
(8,158
)
 
(34,507
)
 
(164,216
)
 
(6,166
)
 
 
 
 
 
 
 
 
Net income (loss) per share — basic
$
(0.24
)
 
$
(1.01
)
 
$
(4.79
)
 
$
(0.18
)
Net income (loss) per share — diluted
$
(0.24
)
 
$
(1.01
)
 
$
(4.79
)
 
$
(0.18
)
 
 
 
 
 
 
 
 
2014
 
 
 
 
 
 
 
Total revenues
$
84,605

 
$
83,013

 
$
58,840

 
$
80,316

Gross profit (loss)
35,025

 
33,261

 
19,606

 
(6,259
)
Operating income (loss)
15,883

 
26,942

 
12,716

 
(16,783
)
Equity in earnings of unconsolidated ventures
991

 
958

 
2,016

 
4,720

Income (loss) before taxes
13,665

 
22,799

 
7,994

 
(18,713
)
Net income (loss) attributable to Forestar Group Inc.
8,334

 
14,822

 
5,227

 
(11,800
)
 
 
 
 
 
 
 
 
Net income (loss) per share — basic
$
0.20

 
$
0.34

 
$
0.12

 
$
(0.34
)
Net income (loss) per share — diluted
$
0.19

 
$
0.34

 
$
0.12

 
$
(0.34
)
 _____________________
(a)Non-cash impairment charges for unproved leasehold interests and proved oil and gas properties included in our quarterly financial results are as follows:
 
First Quarter
 
Second Quarter
 
Third
Quarter
 
Fourth
Quarter
 
(In thousands)
2015
$
7

 
$
45,938

 
$
81,240

 
$
37,646

2014
755

 
584

 
735

 
30,591


Note 21 — Subsequent Events
On January 28, 2016, we announced that our multifamily business is non-core. As a result, we plan to opportunistically exit our multifamily portfolio and no longer allocate capital to new communities in this business.
On February 4, 2016, we entered into a Purchase and Sale Agreement to sell the Radisson Hotel & Suites in Austin for $130,000,000. This transaction is subject to normal closing conditions and is expected to close in second quarter 2016.
On March 1, 2016, we sold our remaining Kansas and Nebraska oil and gas properties for $21,000,000, with a $2,000,000 contingency payment if the WTI oil price exceeds $60 Bbl for 60 consecutive trading days within one year following closing. We will incur an additional loss related to the sale of Kansas and Nebraska oil and gas properties due to allocation of goodwill on a relative fair value basis to the disposal group that constitutes a business.



93


Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 2015
(In thousands)
 
 
 
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 
Gross Amount Carried at End of Period
 
 
 
 
Description
Encumbrances
 
Land
 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 
Total
 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Entitled, Developed, and Under Development Projects:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ARIZONA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pima County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dove Mountain
 
 
$
5,860

 
 
 
$
3

 
 
 
$
5,863

 
 
 
$
5,863

 
 
 
 
 
2015
CALIFORNIA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contra Costa County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
San Joaquin River
 
 
12,225

 
 
 
(3,310
)
 
 
 
8,915

 
 
 
8,915

 
 
 
 
 
(b) 
COLORADO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Douglas County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinery West
 
 
7,308

 
 
 
3,691

 
 
 
10,999

 
 
 
10,999

 
 
 
2006
 
2006
Weld County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Buffalo Highlands
 
 
3,001

 
 
 
547

 
 
 
3,548

 
 
 
3,548

 
 
 
2006
 
2005
Johnstown Farms
 
 
2,749

 
 
 
4,024

 
$
188

 
6,961

 
 
 
6,961

 
 
 
2002
 
2002
Stonebraker
 
 
3,878

 
 
 
(1,469
)
 
 
 
2,409

 
 
 
2,409

 
 
 
2005
 
2005
GEORGIA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cobb County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
West Oaks
 
 
1,669

 
 
 
232

 
 
 
1,901

 
 
 
1,901

 
 
 
2015
 
2015
Paulding County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Harris Place
 
 
265

 
 
 
(111
)
 
 
 
154

 
 
 
154

 
 
 
 
 
2012
Seven Hills
 
 
2,964

 
 
 
145

 
 
 
3,109

 
 
 
3,109

 
 
 
 
 
2012
MISSOURI
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Clay County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Somerbrook
 
 
3,061

 
 
 
(218
)
 
13

 
2,856

 
 
 
2,856

 
 
 
2003
 
2001
NORTH CAROLINA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mecklenburg County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Walden
 
 
12,085

 
 
 
345

 
 
 
12,430

 
 
 
12,430

 
 
 
 
 
2015
SOUTH CAROLINA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lancaster County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ansley Park
 
 
5,089

 
 
 
574

 
 
 
5,663

 
 
 
5,663

 
 
 
 
 
2015
York County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Habersham
 
 
3,877

 
 
 
3,072

 
239

 
7,188

 
 
 
7,188

 
 
 
2014
 
2013

94


Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 2015
(In thousands)
 
 
 
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 
Gross Amount Carried at End of Period
 
 
 
 
Description
Encumbrances
 
Land
 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 
Total
 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
TENNESEE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Williamson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Morgan Farms
 
 
$
6,841

 
 
 
$
(552
)
 
$
166

 
$
6,455

 
 
 
$
6,455

 
 
 
2013
 
2013
Vickery Park
 
 
3,575

 
 
 
560

 
 
 
4,135

 
 
 
4,135

 
 
 
 
 
2015
Weatherford Estates
 
 
856

 
 
 
1,603

 
 
 
2,459

 
 
 
2,459

 
 
 
2015
 
2014
Wilson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beckwith Crossing
 
 
1,294

 
 
 
2,519

 
 
 
3,813

 
 
 
3,813

 
 
 
2015
 
2014
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bastrop County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Hunter’s Crossing
 
 
3,613

 
 
 
5,180

 
358

 
9,151

 
 
 
9,151

 
 
 
2001
 
2001
The Colony
 
 
8,726

 
 
 
15,206

 
161

 
24,093

 
 
 
24,093

 
 
 
1999
 
1999
Bexar County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cibolo Canyons
 
 
17,305

 
 
 
40,243

 
1,202

 
58,750

 
 
 
58,750

 
 
 
2004
 
1986
Calhoun County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Caracol
$
2,237

 
8,603

 
 
 
3,688

 
2,047

 
14,338

 
 
 
14,338

 
 
 
2006
 
2006
Collin County
Lakes of Prosper
 
 
8,951

 
 
 
(3,550
)
 
180

 
5,581

 
 
 
5,581

 
 
 
 
 
2012
Maxwell Creek
 
 
9,904

 
 
 
(7,946
)
 
635

 
2,593

 
 
 
2,593

 
 
 
2000
 
2000
Parkside
 
 
2,177

 
 
 
3,661

 
 
 
5,838

 
 
 
5,838

 
 
 
2014
 
2013
Timber Creek
 
 
7,282

 
 
 
9,137

 
 
 
16,419

 
 
 
16,419

 
 
 
2007
 
2007
Village Park
 
 
4,772

 
 
 
(4,765
)
 
45

 
52

 
 
 
52

 
 
 
 
 
2012
Comal County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oak Creek Estates
 
 
1,921

 
 
 
2,314

 
175

 
4,410

 
 
 
4,410

 
 
 
2006
 
2005
Dallas County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stoney Creek
 
 
12,822

 
 
 
2,783

 
49

 
15,654

 
 
 
15,654

 
 
 
2007
 
2007
Denton County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lantana


 
27,673

 
 
 
(7,382
)
 
 
 
20,291

 
 
 
20,291

 
 
 
2000
 
1999
River's Edge
 
 
1,227

 
 
 
381

 
 
 
1,608

 
 
 
1,608

 
 
 
 
 
2014
The Preserve at Pecan Creek
 
 
5,855

 
 
 
(3,905
)
 
436

 
2,386

 
 
 
2,386

 
 
 
2006
 
2005
Fort Bend County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summer Lakes

 
4,269

 
 
 
968

 
 
 
5,237

 
 
 
5,237

 
 
 
2013
 
2012
Summer Park

 
4,804

 
 
 
57

 
 
 
4,861

 
 
 
4,861

 
 
 
2013
 
2012
Willow Creek Farms
459

 
3,479

 
 
 
(311
)
 
90

 
3,258

 
 
 
3,258

 
 
 
2012
 
2012
Harris County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Barrington
 
 
8,950

 
 
 
(7,062
)
 
 
 
1,888

 
 
 
1,888

 
 
 
 
 
2011
City Park
1,659

 
3,946

 
 
 
1,463

 
1,641

 
7,050

 
 
 
7,050

 
 
 
2002
 
2001
Imperial Forest
 
 
5,345

 
 
 
819

 
 
 
6,164

 
 
 
6,164

 
 
 
2015
 
2014

95


Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 2015
(In thousands)
 
 
 
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 
Gross Amount Carried at End of Period
 
 
 
 
Description
Encumbrances
 
Land
 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 
Total
 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Hays County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Arrowhead Ranch
 
 
$
12,856

 
 
 
$
6,537

 
 
 
$
19,393

 
 
 
$
19,393

 
 
 
2015
 
2007
Nueces County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Tortuga Dunes
 
 
12,080

 
 
 
9,670

 
 
 
21,750

 
 
 
21,750

 
 
 
 
 
2006
Tarrant County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summer Creek Ranch
 
 
2,887

 
 
 
(1,601
)
 
 
 
1,286

 
 
 
1,286

 
 
 
 
 
2012
The Bar C Ranch
 
 
1,365

 
 
 
3,258

 
$
32

 
4,655

 
 
 
4,655

 
 
 
 
 
2012
Williamson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
La Conterra
 
 
4,024

 
 
 
(2,790
)
 
293

 
1,527

 
 
 
1,527

 
 
 
 
 
2006
Westside at Buttercup Creek
 
 
13,149

 
 
 
(13,586
)
 
488

 
51

 
 
 
51

 
 
 
1993
 
1993
Other
 
 
8,443

 
 
 
(4,097
)
 
653

 
4,999

 
 
 
4,999

 
 
 
 
 
 
Total Entitled, Developed, and Under Development Projects
$
4,355

 
$
283,025

 
$
—

 
$
60,025

 
$
9,091

 
$
352,141

 
$
—

 
$
352,141

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land and Land in Entitlement:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CALIFORNIA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Los Angeles County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Land In Entitlement Process
 
 
$
3,950

 
 
 
$
19,564

 
 
 
$
23,514

 
 
 
$
23,514

 
 
 
 
 
1997
GEORGIA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bartow County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
4,057

 
 
 
(2,440
)
 
 
 
1,617

 
 
 
1,617

 
 
 
 
 
(b) 
Carroll County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
13,564

 
 
 
2,580

 
 
 
16,144

 
 
 
16,144

 
 
 
 
 
(b) 
Cherokee County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
6,043

 
 
 
536

 
 
 
6,579

 
 
 
6,579

 
 
 
 
 
(b) 
Coweta County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
3,089

 
 
 
1,343

 
 
 
4,432

 
 
 
4,432

 
 
 
 
 
(b) 
Dawson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
2,228

 
 
 
3,381

 
 
 
5,609

 
 
 
5,609

 
 
 
 
 
(b) 
Gilmer County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
2,748

 
 
 
(62
)
 
 
 
2,686

 
 
 
2,686

 
 
 
 
 
(b) 
Haralson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
195

 
 
 
88

 
 
 
283

 
 
 
283

 
 
 
 
 
(b) 
Lumpkin County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
3,015

 
 
 
(93
)
 
 
 
2,922

 
 
 
2,922

 
 
 
 
 
(b) 
Paulding County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
7,494

 
 
 


 
 
 
7,494

 
 
 
7,494

 
 
 
 
 
(b) 

96


Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 2015
(In thousands)
 
 
 
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 
Gross Amount Carried at End of Period
 
 
 
 
Description
Encumbrances
 
Land
 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and
Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 
Total
 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Pickens County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
$
3,150

 
 
 
$
(108
)
 
 
 
$
3,042

 
 
 
$
3,042

 
 
 
 
 
(b) 
Polk County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
2,354

 
 
 
(198
)
 
 
 
2,156

 
 
 
2,156

 
 
 
 
 
(b) 
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bexar County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
 
 
 
 
3,036

 
 
 
3,036

 
 
 
3,036

 
 
 
 
 
(b) 
Harris County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Land in Entitlement Process
 
 
685

 
 
 
1,151

 
 
 
1,836

 
 
 
1,836

 
 
 
 
 
(b) 
Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
9,170

 
 
 
7,661

 
 
 
16,831

 
 
 
16,831

 
 
 
 
 
(b) 
Total Undeveloped Land and Land in Entitlement
$
—

 
$
61,742

 
$
—

 
$
36,439

 
$
—

 
$
98,181

 
$
—

 
$
98,181

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Producing Properties:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NORTH CAROLINA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mecklenburg County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dillon
 
 
$
5,779

 
 
 
$
14,208

 
 
 
$
19,987

 
 
 
$
19,987

 
 
 
 
 
2012
TENNESSEE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Davidson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Music Row
 
 
6,607

 
 
 
3,340

 
 
 
9,947

 
 
 
9,947

 
 
 
 
 
2014
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Travis County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Eleven
$
23,936

 
7,940

 
$
45,956

 
—

 
 
 
7,940

 
$
45,956

 
53,896

 
$
(2,861
)
 
2013
 
2014
Downtown Edge
 
 
11,202

 
 
 
1,504

 
 
 
12,706

 
 
 
12,706

 
 
 
 
 
2014
Radisson Hotel & Suites
15,400

 
 
 
10,603

 
52,286

 
 
 
—

 
62,889

 
62,889

 
(29,268
)
 
 
 
(b) 
West Austin
 
 
7,275

 
 
 
1,822

 
 
 
9,097

 
 
 
9,097

 
 
 
 
 
2014
Total Income Producing Properties
$
39,336

 
$
38,803

 
$
56,559

 
$
73,160

 
$
—

 
$
59,677

 
$
108,845

 
$
168,522

 
$
(32,129
)
 
 
 
 
Total
$
43,691

 
$
383,570

 
$
56,559

 
$
169,624

 
$
9,091

 
$
509,999

 
$
108,845

 
$
618,844

 
$
(32,129
)
 
 
 
 
  _____________________
(a) 
We do not capitalize carrying costs until development begins.
(b) 
The acquisition date is not available.


97


Reconciliation of real estate:
 
 
2015
 
2014
 
2013
 
 
(In thousands)
Balance at beginning of year
 
$
607,133

 
$
547,530

 
$
545,370

Amounts capitalized
 
124,633

 
214,184

 
111,428

Amounts retired or adjusted
 
(112,922
)
 
(154,581
)
 
(109,268
)
Balance at close of period
 
$
618,844

 
$
607,133

 
$
547,530

Reconciliation of accumulated depreciation:
 
 
2015
 
2014
 
2013
 
 
(In thousands)
Balance at beginning of year
 
$
(31,377
)
 
$
(28,066
)
 
$
(28,220
)
Depreciation expense
 
(6,810
)
 
(3,319
)
 
(2,185
)
Amounts retired or adjusted
 
6,058

 
8

 
2,339

Balance at close of period
 
$
(32,129
)
 
$
(31,377
)
 
$
(28,066
)

Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.

Item 9A.
Controls and Procedures.
(a) Disclosure controls and procedures
Our management, with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act of 1934), as amended (or the Exchange Act)) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and were effective in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
(b) Internal control over financial reporting
Management’s report on internal control over financial reporting and the report of our independent registered public accounting firm are included in Part II, Item 8 of this Annual Report on Form 10-K.
(c) Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.
Other Information. 
None.


98


PART III
 
Item 10.
Directors, Executive Officers and Corporate Governance.
Set forth below is certain information about the members of our Board of Directors:
Name
 
Age
 
Year First
Elected to
the Board
 
Principal Occupation
James A. Rubright
 
69
 
2007
 
Retired Chairman and Chief Executive Officer of Rock-Tenn Company
William G. Currie
 
68
 
2007
 
Chairman of Universal Forest Products, Inc.
M. Ashton Hudson
 
43
 
2016
 
President and General Counsel of Rock Creek Capital Group, Inc.
William C. Powers, Jr.
 
69
 
2007
 
Professor of Law at The University of Texas at Austin
Daniel B. Silvers
 
39
 
2015
 
Managing Member at Matthews Lane Capital Partners LLC
Richard M. Smith
 
70
 
2007
 
President of Pinkerton Foundation
Richard D. Squires
 
58
 
2016
 
Managing Director and Co-Founder of Lennox Capital Partners, LLC
Phillip J. Weber
 
55
 
2015
 
Chief Executive Officer of Forestar Group Inc.
David L. Weinstein
 
49
 
2015
 
Former President and Chief Executive Officer of MPG Office Trust, Inc.
The remaining information required by this item is incorporated herein by reference from our definitive proxy statement, involving the election of directors, to be filed pursuant to Regulation 14A with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K (or Definitive Proxy Statement). Certain information required by this item concerning executive officers is included in Part I of this report.

Item 11.
Executive Compensation.
The information required by this item is incorporated by reference from our Definitive Proxy Statement.

Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Equity Compensation Plan Information
We have only one equity compensation plan, the Forestar 2007 Stock Incentive Plan. It was approved by our sole stockholder prior to spin-off and material terms and amendments thereto were subsequently approved by our stockholders. Information at year-end 2015 about our equity compensation plan under which our common stock may be issued follows:
Plan Category
Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights(1)(2)
 
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
 
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column (a))
 
(a)
 
(b)
 
(c)
Equity compensation plans approved by security holders
3,697,801

 
$
21.38

 
635,306

Equity compensation plans not approved by security holders
None

 
None

 
None

Total
3,697,801

 
$
21.38

 
635,306

  _____________________
(1) 
Includes 500,798 shares issuable to former Temple-Inland and the other spin-off entity personnel resulting from the equitable adjustment of Temple-Inland equity awards in connection with our spin-off.
(2) 
Includes 417,151 equity-settled restricted stock units, 372,467 market-leveraged stock units and 192,959 performance stock units, which are excluded from the calculation of weighted-average exercise price. Market-leveraged stock unit and performance stock unit awards will be settled in common stock based upon performance over three years from the date of grant. For market-leveraged stock units, the number of shares to be issued could range from a high of 558,701 shares if our stock price increases by 50 percent or more, to 186,234 shares if our stock price decreases by 50 percent, or could be zero if our stock price decreases by more than 50 percent, the minimum threshold performance. For performance stock units, the number of shares to be issued could range from 385,918 shares at maximum performance to 192,959 at threshold performance, or could be zero below threshold performance.

99


The remaining information required by this item is incorporated by reference from our Definitive Proxy Statement.

Item 13.
Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from our Definitive Proxy Statement.

Item 14.
Principal Accountant Fees and Services.
The information required by this item is incorporated by reference from our Definitive Proxy Statement.

PART IV

Item 15.
Exhibits and Financial Statement Schedules.
(a)
Documents filed as part of this report.
(1)
 Financial Statements
Our Consolidated Financial Statements are included in Part II, Item 8 of this Annual Report on Form 10-K.
(2)
 Financial Statement Schedules
Schedule III — Consolidated Real Estate and Accumulated Depreciation is included in Part II, Item 8 of this Annual Report on Form 10-K.
Schedules other than those listed above are omitted as the required information is either inapplicable or the information is presented in our Consolidated Financial Statements and notes thereto.
(3)
Exhibits
The exhibits listed in the Exhibit Index in (b) below are filed or incorporated by reference as part of this Annual Report on Form 10-K.
(b)
Exhibits
Exhibit
Number
 
Exhibit
3.1
 
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on December 11, 2007).
3.2
 
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K filed with the Commission on December 11, 2007).
3.3
 
First Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 19, 2008).
3.4
 
Second Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.5 of the Company’s Annual Report on Form 10-K filed with the Commission on March 5, 2009).
3.5
 
Certificate of Ownership and Merger, dated November 21, 2008 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on November 24, 2008).
3.6
 
Third Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K filed with the Commission on November 24, 2008).
3.7
 
Fourth Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on November 26, 2012).
3.8
 
Fifth Amendment to Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed with the Commission on September 28, 2015).
3.9
 
Certificate of Amendment to Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q filed with the Commission on November 6, 2015).
4.1
 
Specimen Certificate for shares of common stock, par value $1.00 per share (incorporated by reference to Exhibit 4.1 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
4.2
 
Indenture, dated February 26, 2013 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.3
 
Supplemental Indenture, dated February 26, 2013 (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.4
 
Form of 3.75% Convertible Senior Notes due 2020 (included in Exhibit 4.3 above) (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on February 26, 2013).
4.5
 
Second Supplemental Indenture, dated November 27, 2013 (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).

100


4.6
 
Purchase Contract Agreement, dated November 27, 2013, between the Company and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.7
 
Form of 6.00% Tangible Equity Unit (included in Exhibit 4.6 above) (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.8
 
Form of Purchase Contract (included in Exhibit 4.6 above) (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.9
 
Form of 4.50% Senior Amortizing Notes due 2016 (included in Exhibit 4.5 above) (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on November 27, 2013).
4.10
 
Indenture, dated May 12, 2014 (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 15, 2014).
4.11
 
Form of 8.500% Senior Secured Notes due 2022 (included in Exhibit 4.10 above) (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 15, 2014).
10.1†
 
Forestar Real Estate Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.5 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.2†
 
Amendment No. 1 to Forestar Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.3†
 
Forestar Real Estate Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.6 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.4†
 
Amended and Restated Forestar Group Inc. Amended and Restated Directors' Fee Deferral Plan (incorporated by reference to Exhibit 10.5 of the Company's Annual Report on Form 10-K filed with the Commission on March 11, 2014).
10.5†
 
Form of Indemnification Agreement to be entered into between the Company and each of its directors (incorporated by reference to Exhibit 10.9 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.6†
 
Form of Change in Control/Severance Agreement between the Company and its named executive officers (incorporated by reference to Exhibit 10.10 to the Company’s Form 10 filed with the Commission on August 10, 2007).
10.7†
 
Employment Agreement between the Company and James M. DeCosmo dated August 9, 2007 (incorporated by reference to Exhibit 10.11 of Amendment No. 5 to the Company’s Form 10 filed with the Commission on December 10, 2007).
10.8†
 
Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.12 of the Company’s Annual Report on Form 10-K filed with the Commission on March 5, 2009).
10.9†
 
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.10 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.10†
 
Form of Restricted Stock Units Agreement (incorporated by reference to Exhibit 10.11 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.11†
 
Form of Stock Appreciation Right Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 12, 2009).
10.12†
 
First Amendment to the Forestar Real Estate Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on May 13, 2009).
10.13†
 
Second Amendment to the Forestar Group Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.22 to the Company’s Annual Report on Form 10-K filed with the Commission on March 3, 2010).
10.14†
 
First Amendment to Employment Agreement, dated as of November 10, 2010, by and between the Company and James M. DeCosmo (incorporated by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K filed with the Commission on March 2, 2011).
10.15†
 
Form of Market-Leveraged Stock Unit Award Agreement (incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.16†
 
Form of Indemnification Agreement entered into between the Company and each of its executive officers (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K filed with the Commission on March 14, 2013).
10.17
 
Guaranty Agreement, dated June 28, 2012, by Forestar (USA) Real Estate Group Inc. in favor of Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 29, 2012).
10.18
 
Guaranty Agreement, dated May 24, 2012, by Forestar (USA) Real Estate Group Inc. in favor of Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 29, 2012).
10.19†
 
Amendment No. 2 to Forestar Group Inc. Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.25 of the Company's Annual Report on Form 10-K filed with the Commission on March 11, 2014).
10.20
 
Agreement of Guaranty and Suretyship (Completion), dated January 17, 2014, by Forestar Group Inc. in favor of PNC Bank, National Association (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on January 17, 2014).
10.21
 
Agreement of Guaranty and Suretyship (Payment), dated January 17, 2014, by Forestar Group Inc. in favor of PNC Bank, National Association (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on January 17, 2014).
10.22
 
Third Amended and Restated Revolving Credit Agreement dated May 15, 2014, by and among the Company, Forestar (USA) Real Estate Group Inc. and certain of its wholly-owned subsidiaries; Key Bank National Association, as lender, swing line lender and agent, the lenders party thereto; and the other parties thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on May 16, 2014).
10.23
 
Guaranty, dated July 15, 2014, by Forestar (USA) Real Estate Group Inc. in favor of Regions Bank (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed with the Commission on July 18, 2014).
10.24†
 
Separation Agreement and Release of All Claims, dated January 8, 2015, between Flavious J. Smith, Jr. and Forestar Group Inc. (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed with the Commission on January 14, 2015).

101


10.25
 
Director Nomination Agreement, dated February 9, 2015, by and among Forestar Group Inc., SpringOwl Associates LLC and Cove Street Capital, LLC (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 9, 2015).
10.26
 
Limited Waiver and Amendment to the Third Amended and Restated Revolving Credit Agreement, dated September 30, 2015, by and among the Company, Forestar (USA) Real Estate Group Inc. and certain of its wholly-owned subsidiaries signatory thereto, KeyBank National Association, as lender, swing line lender and agent, the lenders party thereto, and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 6, 2015).
10.27
 
Construction Loan Agreement between FMF Morehead LLC, a subsidiary of the Company, and PNC Bank, National Association, dated October 16, 2015 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on October 21, 2015).
10.28
 
First Amendment to Third Amended and Restated Revolving Credit Agreement dated December 30, 2015, by and among the Company, Forestar (USA) Real Estate Group Inc. and certain of its wholly-owned subsidiaries signatory thereto, KeyBank National Association, as lender, swing line lender and agent, the lenders party thereto, and the other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on December 31, 2015).
10.29†
 
Employment Agreement, dated October 21, 2015, between the Company and Phillip J. Weber (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 26, 2015).
10.30†
 
Separation Agreement and Release of All Claims, dated October 21, 2015, between the Company and Christopher L. Nines (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on October 26, 2015).
21.1*
 
List of Subsidiaries of the Company.
23.1*
 
Consent of Ernst & Young LLP.
23.2*
 
Consent of Netherland, Sewell & Associates, Inc.
31.1*
 
Certification of Chief Executive Officer pursuant to Exchange Act rule 13a-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
 
Certification of Chief Financial Officer pursuant to Exchange Act rule 13a-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
 
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*
 
Reserve report of Netherland, Sewell & Associates, Inc., dated February 24, 2016.
101.1*
 
The following materials from the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income (Loss) and Comprehensive Income (Loss), (iii) Consolidated Statement of Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.
  _____________________
*
Filed herewith.
†
Management contract or compensatory plan or arrangement.

102


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
FORESTAR GROUP INC.
 
 
 
 
By:
/s/ Phillip J. Weber
 
 
Phillip J. Weber
 
 
Chief Executive Officer
Date: March 4, 2016
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
 
Capacity
 
Date
/s/ Phillip J. Weber
 
Director and Chief Executive Officer
(Principal Executive Officer)
 
March 4, 2016
Phillip J. Weber
 
 
 
 
 
/s/ Charles D. Jehl
 
Chief Financial Officer
(Principal Financial Officer)
 
March 4, 2016
Charles D. Jehl
 
 
 
 
 
/s/ Sabita C. Reddy
 
Vice President Accounting
(Principal Accounting Officer)
 
March 4, 2016
Sabita C. Reddy
 
 
 
 
 
/s/ James A. Rubright
 
Non-Executive
Chairman of the Board
 
March 4, 2016
James A. Rubright
 
 
 
 
 
/s/ William G. Currie
 
Director
 
March 4, 2016
William G. Currie
 
 
 
 
 
/s/ M. Ashton Hudson
 
Director
 
March 4, 2016
M. Ashton Hudson
 
 
 
 
 
 
 
/s/ William C. Powers, Jr.
 
Director
 
March 4, 2016
William C. Powers, Jr.
 
 
 
 
 
/s/ Daniel B. Silvers
 
Director
 
March 4, 2016
Daniel B. Silvers
 
 
 
 
 
/s/ Richard M. Smith
 
Director
 
March 4, 2016
Richard M. Smith
 
 
 
 
 
/s/ Richard D. Squires
 
Director
 
March 4, 2016
Richard D. Squires
 
 
 
 
 
 
 
/s/ David L. Weinstein
 
Director
 
March 4, 2016
David L. Weinstein
 
 

103
Exhibit


Exhibit 21.1
FORESTAR GROUP INC.
SUBSIDIARIES
Legal Entity
 
Jurisdiction
 
% Ownership
Forestar (USA) Real Estate Group Inc.
 
Delaware
 
100%
242, LLC
 
Texas
 
50%
360 Development LLC
 
Delaware
 
100%
1270 Spring Street Development, LLC
 
Delaware
 
100%
4S/RPG Land Company LP
 
Texas
 
100%
Arrowhead Ranch Utility Company LLC
 
Texas
 
100%
Bandera/Lantana, LP
 
Texas
 
100%
Bandera/Lantana II, LP
 
Texas
 
100%
Bandera/Lantana III, LP
 
Texas
 
100%
Bandera IV/Kendall III, LP
 
Texas
 
100%
Bellaire/Lantana II LP
 
Texas
 
100%
Blackberry Island, LP
 
Texas
 
74%
Canyon Land Holdings LLC
 
Delaware
 
100%
Carlisle/Lantana III LP
 
Texas
 
100%
CL Ashton Woods, LP
 
Texas
 
80%
CL Realty, LLC
 
Delaware
 
50%
CL/RPG Land Company, LP
 
Texas
 
100%
CL Texas I GP, L.L.C.
 
Georgia
 
100%
CL Waterford, LLC
 
Texas
 
100%
CL Westpark, LLC
 
Georgia
 
100%
CREA FMF Nashville LLC
 
Delaware
 
30%
Dalmac-Shelton Fannin Farms, Ltd.
 
Texas
 
50%
Dewberry Island LP
 
Texas
 
75%
Elan 99, LLC
 
Delaware
 
90%
FirstLand Investment Corporation
 
Texas
 
100%
FMF Cedar Hill LLC
 
Delaware
 
100%
FMF Construction LLC
 
Delaware
 
100%
FMF Development LLC
 
Delaware
 
100%
FMF Littleton LLC
 
Delaware
 
25%
FMF Morehead LLC
 
Delaware
 
100%
FMF MSW LLC
 
Delaware
 
100%
FMF Peakview Manager LLC
 
Delaware
 
100%
FMF Peakview LLC
 
Delaware
 
20%
FMF Pressler Park LLC
 
Delaware
 
100%
FMF Robertson Hill LLC
 
Delaware
 
100%
Forestar Capital Inc.
 
Delaware
 
100%
Forestar Hotel Holding Company Inc.
 
Nevada
 
100%
Capitol of Texas Insurance Group Inc.
 
Delaware
 
100%
Top of Westgate Corporation
 
Texas
 
100%
CCA Hospitality, Inc.
 
Texas
 
100%
Forestar Minerals LP
 
Delaware
 
100%
Forestar Mountain Investments LLC
 
Delaware
 
100%
Forestar Multifamily Fund GP LLC
 
Delaware
 
100%
Forestar Multifamily Fund LP
 
Delaware
 
100%
Forestar Oil & Gas LLC
 
Delaware
 
100%
Forestar Petroleum Corporation
 
Delaware
 
100%
SECO Energy Corporation
 
Nevada
 
100%
United Oil Corporation
 
Oklahoma
 
100%
CREDO Exploration Program Ltd 1979
 
Colorado
 
59%
Fortuna Energy LLC
 
Colorado
 
75%
McKinley Resources LLC
 
Colorado
 
100%
Forestar Real Estate Group Inc.
 
Delaware
 
100%
Forestar Realty Inc.
 
Delaware
 
100%




Legal Entity
 
Jurisdiction
 
% Ownership
TEMCO Associates, LLC
 
Georgia
 
50%
FORCO Real Estate Inc.
 
Delaware
 
100%
Forestar/MWC WCF LLC
 
Delaware
 
90%
FOR/SR Forsyth LLC
 
Delaware
 
90%
Gaillardia/Lantana, LP
 
Texas
 
100%
GBF/LIC 288, Ltd.
 
Texas
 
75%
Gulf Coast-Stonehill, LLC
 
Delaware
 
80%
Hickory Hill Development, LP
 
Texas
 
100%
HM Pfluger, Ltd.
 
Texas
 
50%
HM Stonewall Estates, Ltd.
 
Texas
 
50%
Isabel/Lantana, LP
 
Texas
 
100%
Johnstown Farms, LLC
 
Delaware
 
100%
Juniper/Lantana, LP
 
Texas
 
100%
Kendall/Lantana, LP
 
Texas
 
100%
Kendall/Lantana II, LP
 
Texas
 
100%
LIC Ventures Inc.
 
Delaware
 
100%
LM Land Holdings, LP
 
Texas
 
38%
Madison/Lantana, LP
 
Texas
 
100%
Madison/Lantana II, LP
 
Texas
 
100%
Madison/Lantana III, LP
 
Texas
 
100%
Magnolia/Lantana IV, LP
 
Texas
 
100%
Magnolia/Lantana V, LP
 
Texas
 
100%
Magnolia/Lantana VI, LP
 
Texas
 
100%
Olympia Joint Venture (general partnership)
 
Texas
 
100%
Palmetto/Lantana, LP
 
Texas
 
100%
Preserve at Mustang Island LLC, (The)
 
Delaware
 
85%
PSW Communities, LP
 
Texas
 
89%
Sabine Real Estate Company
 
Delaware
 
100%
San Jacinto I LLC
 
Texas
 
100%
Stoney Creek Properties LLC
 
Delaware
 
100%
Summer Creek Development LLC
 
Texas
 
100%
SWR Holdings LLC
 
Delaware
 
100%
Sustainable Water Resources LLC
 
Texas
 
100%
Timber Creek Properties LLC
 
Delaware
 
88%
Westlake Acquisition Partners LLC
 
Delaware
 
100%



Exhibit


Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the following Registration Statements:
1) Registration Statement (Form S-8 No. 333-148375) of Forestar Group Inc.
2) Registration Statement (Form S-8 No. 333-159214) of Forestar Group Inc.
3) Registration Statement (Form S-3 No. 333-179612) of Forestar Group Inc., and
4) Registration Statement (Form S-3ASR No. 333-192442) of Forestar Group Inc.
of our reports dated March 4, 2016, with respect to the consolidated financial statements and schedule of Forestar Group Inc. and the effectiveness of internal control over financial reporting of Forestar Group Inc. included in this Annual Report (Form 10-K) of Forestar Group Inc. for the year ended December 31, 2015.

/s/ Ernst & Young LLP
 
 
Austin, Texas
March 4, 2016



Exhibit

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the reference of our firm and to the use of our reports effective as of December 31, 2015; December 31, 2014; and December 31, 2013, dated February 24, 2016, February 12, 2015, February 6, 2014, respectively, in this Forestar Group Inc. Annual Report on Form 10-K for the year ended December 31, 2014, and to the incorporation by reference of our name and our reports into Forestar Group Inc.’s Registration Statements on Form S-3 (file no. 333-179612), Form S3ASR (file no. 333-192442), and on Form S-8 (files nos. 333-148375 and 333-159214).
  
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:
/s/ C.H. (Scott) Rees III
 
 
 
 
C.H. (Scott) Rees III, P.E.
 
Chairman and Chief Executive Officer

Dallas, Texas
March 4, 2016



Exhibit


Exhibit 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO EXCHANGE ACT RULE 13a-14(a)
I, Phillip J. Weber, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Forestar Group Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
/s/ Phillip J. Weber
 
Phillip J. Weber
 
Chief Executive Officer
Date: March 4, 2016



Exhibit


Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO EXCHANGE ACT RULE 13a-14(a)
I, Charles D. Jehl, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Forestar Group Inc.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
/s/ Charles D. Jehl
 
Charles D. Jehl
 
Chief Financial Officer
Date: March 4, 2016



Exhibit


Exhibit 32.1
Certification of Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
I, Phillip J. Weber, Chief Executive Officer of Forestar Group Inc., hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, this Annual Report on Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in this Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Forestar Group Inc.
/s/ Phillip J. Weber
 
Phillip J. Weber
 

March 4, 2016



Exhibit


Exhibit 32.2
Certification of Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
I, Charles D. Jehl, Chief Financial Officer of Forestar Group Inc., hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, this Annual Report on Form 10-K fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in this Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Forestar Group Inc.
/s/ Charles D. Jehl
 
Charles D. Jehl
 

March 4, 2016




Exhibit
Exhibit 99.1

February 24, 2016

Mr. Charles D. Jehl
Forestar Group Inc.
1801 Broadway, Suite 600
Denver, Colorado 80202

Dear Mr. Jehl:

In accordance with your request, we have estimated the proved developed reserves and future revenue, as of December 31, 2015, to the Forestar Group Inc. (Forestar) interest in certain oil and gas properties located in the United States. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Forestar. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Forestar's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Forestar interest in these properties, as of December 31, 2015, to be:
 
 
Net Reserves
 
Future Net Revenue (M$)
 
 
Oil
 
NGL
 
Gas
 
 
 
Present Worth
Category
 
(MBBL)
 
(MBBL)
 
(MMCF)
 
Total
 
at 10%
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Producing
 
4,547.5
 
413.4
 
9,220.8
 
120,014.0
 
78,440.2
Proved Developed Non-Producing
 
218.0
 
0.0
 
0.0
 
4,988.9
 
2,956.8
 
 
 
 
 
 
 
 
 
 
 
Total Proved Developed
 
4,765.4
 
413.4
 
9,220.8
 
125,002.9
 
81,397.0
Totals may not add because of rounding.
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed reserves. As requested, proved undeveloped, probable, and possible reserves that may exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Forestar's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Forestar's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.





Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2015. For oil and NGL volumes, the average West Texas Intermediate spot price of $50.28 per barrel is adjusted by lease for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.587 per MMBTU is adjusted by lease for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $41.79 per barrel of oil, $8.74 per barrel of NGL, and $1.750 per MCF of gas.

Operating costs used in this report are based on operating expense records of Forestar. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Forestar's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into per-well costs and per-unit-of-production costs and are not escalated for inflation.

Capital costs used in this report were provided by Forestar and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Forestar interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Forestar receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Forestar, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering


and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Forestar, other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  Gregory S. Cohen, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience.  John G. Hattner, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience.  We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.


 
 
 
Sincerely,
 
 
 
 
 
 
 
 
NETHERLAND, SEWELL & ASSOCIATES, INC.
 
 
 
Texas Registered Engineering Firm F-2699
 
 
 
 
 
 
 
 
 
 
 
 
 
By:
/s/ C.H. (Scott) Rees III
 
 
 
 
C.H. (Scott) Rees, III
 
 
 
 
Chairman and Chief Executive Officer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
By:
/s/ Gregory S. Cohen
 
By:
/s/ John G. Hattner
 
Gregory S. Cohen, P.E. 117412
 
 
John G. Hattner, P.G. 559
 
Petroleum Engineer
 
 
Senior Vice President
 
 
 
 
 
Date Signed: February 24, 2016
 
Date Signed: February 24, 2016
 
 
 
 
 
GSC:TNU
 
 
 
 
 
 
 
 


DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)


The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)
Same environment of deposition;
(iii)
Similar geological structure; and
(iv)
Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves - Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves - Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.



DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)


(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)
Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii)
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii)
Dry hole contributions and bottom hole contributions.
(iv)
Costs of drilling and equipping exploratory wells.
(v)
Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is



DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)


not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)
Oil and gas producing activities include:

(A)
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
(B)
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1)
Lifting the oil and gas to the surface; and
(2)
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D)
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)
Oil and gas producing activities do not include:

(A)
Transporting, refining, or marketing oil and gas;
(B)
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;



DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)


(C)
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D)
Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv)
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.



DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)


(20) Production costs.

(i)
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)
Costs of labor to operate the wells and related equipment and facilities.
(B)
Repairs and maintenance.
(C)
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D)
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)
Severance taxes.

(ii)
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)
The area of the reservoir considered as proved includes:

(A)
The area identified by drilling and limited by fluid contacts, if any, and
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an



DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)


analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)
The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a.    Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.    Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.    Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.



DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)


b.    Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.    Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.    Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.    Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.    Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects - such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations - by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company's historical record at completing development of comparable long-term projects;



DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)


The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.





for-20151231.xml
Attachment: XBRL INSTANCE DOCUMENT

for-20151231.xsd
Attachment: XBRL TAXONOMY EXTENSION SCHEMA DOCUMENT

for-20151231_cal.xml
Attachment: XBRL TAXONOMY EXTENSION CALCULATION LINKBASE DOCUMENT

for-20151231_def.xml
Attachment: XBRL TAXONOMY EXTENSION DEFINITION LINKBASE DOCUMENT

for-20151231_lab.xml
Attachment: XBRL TAXONOMY EXTENSION LABEL LINKBASE DOCUMENT

for-20151231_pre.xml
Attachment: XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE DOCUMENT

v3.3.1.900
Document and Entity Information - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2015
Feb. 29, 2016
Jun. 30, 2015
Entity Information [Line Items]      
Document Type 10-K    
Amendment Flag false    
Document Period End Date Dec. 31, 2015    
Document Fiscal Year Focus 2015    
Document Fiscal Period Focus FY    
Trading Symbol FOR    
Entity Registrant Name FORESTAR GROUP INC.    
Entity Central Index Key 0001406587    
Current Fiscal Year End Date --12-31    
Entity Well-known Seasoned Issuer No    
Entity Current Reporting Status Yes    
Entity Voluntary Filers No    
Entity Filer Category Accelerated Filer    
Entity Common Stock, Shares Outstanding   33,906,986  
Entity Public Float     $ 275
v3.3.1.900
CONSOLIDATED BALANCE SHEET - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
ASSETS    
Cash and cash equivalents $ 96,442 $ 170,127
Real estate, net 586,715 575,756
Oil and gas properties and equipment, net 80,613 263,493
Investment in unconsolidated ventures 82,453 65,005
Timber 7,683 8,315
Receivables, net 23,656 24,589
Income taxes receivable 12,056 7,503
Prepaid expenses 3,213 6,000
Property and equipment, net 10,732 11,627
Deferred tax asset, net 0 40,624
Goodwill and other intangible assets 63,128 66,131
Other assets 13,822 19,029
TOTAL ASSETS 980,513 1,258,199
LIABILITIES AND EQUITY    
Accounts payable 11,959 20,400
Accrued employee compensation and benefits 5,547 8,323
Accrued property taxes 4,788 5,966
Accrued interest 3,267 3,451
Deferred tax liability, net 1,037 0
Earnest money deposits 10,214 10,045
Other accrued expenses 23,481 35,729
Other liabilities 26,323 31,799
Debt 389,782 432,744
TOTAL LIABILITIES $ 476,398 $ 548,457
COMMITMENTS AND CONTINGENCIES
Forestar Group Inc. shareholders’ equity:    
Common stock, par value $1.00 per share, 200,000,000 authorized shares, 36,946,603 issued at December 31, 2015 and December 31, 2014 $ 36,947 $ 36,947
Additional paid-in capital 561,850 558,945
Retained earnings (Accumulated deficit) (46,046) 167,001
Treasury stock, at cost, 3,203,768 shares at December 31, 2015 and 3,485,278 shares at December 31, 2014 (51,151) (55,691)
Total Forestar Group Inc. shareholders’ equity 501,600 707,202
Noncontrolling interests 2,515 2,540
TOTAL EQUITY 504,115 709,742
TOTAL LIABILITIES AND EQUITY $ 980,513 $ 1,258,199
v3.3.1.900
CONSOLIDATED BALANCE SHEET (Parenthetical) - $ / shares
Dec. 31, 2015
Dec. 31, 2014
Statement of Financial Position [Abstract]    
Common stock, par value $ 1.00 $ 1.00
Common stock, shares authorized 200,000,000 200,000,000
Common stock, shares issued 36,946,603 36,946,603
Treasury stock, common shares 3,203,768 3,485,278
v3.3.1.900
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
REVENUES      
Real estate sales and other $ 120,022 $ 171,672 $ 152,684
Commercial and income producing properties 82,808 41,440 95,327
Real estate 202,830 213,112 248,011
Oil and gas 52,939 84,300 72,313
Other natural resources 6,652 9,362 10,721
Total revenues 262,421 306,774 331,045
COST AND EXPENSES      
Cost of real estate sales and other (52,640) (86,432) (76,628)
Cost of commercial and income producing properties (61,251) (37,332) (80,166)
Cost of oil and gas producing activities (224,400) (98,371) (42,067)
Cost of other natural resources (3,081) (3,006) (2,033)
Other operating (59,359) (58,683) (60,359)
General and administrative (27,253) (22,230) (28,376)
Total expenses (427,984) (306,054) (289,629)
GAIN ON SALE OF ASSETS 879 38,038 5,161
OPERATING INCOME (LOSS) (164,684) 38,758 46,577
Equity in earnings of unconsolidated ventures 16,008 8,685 8,737
Interest expense (34,066) (30,286) (20,004)
Other non-operating income 3,006 8,588 6,959
INCOME (LOSS) BEFORE TAXES (179,736) 25,745 42,269
Income tax expense (32,635) (8,657) (7,208)
Net income (212,371) 17,088 35,061
Less: Net (income) attributable to noncontrolling interests (676) (505) (5,740)
NET INCOME (LOSS) ATTRIBUTABLE TO FORESTAR GROUP INC. $ (213,047) $ 16,583 $ 29,321
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING      
Basic (usd per share) 34,266 35,317 35,365
Diluted (usd per share) 34,266 43,596 36,813
NET INCOME (LOSS) PER COMMON SHARE      
Basic (usd per share) $ (6.22) $ 0.38 $ 0.81
Diluted (usd per share) $ (6.22) $ 0.38 $ 0.80
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO FORESTAR GROUP INC. $ (213,047) $ 16,583 $ 29,321
v3.3.1.900
CONSOLIDATED STATEMENTS OF EQUITY - USD ($)
Total
Common Stock [Member]
Additional Paid-in Capital [Member]
Treasury Stock [Member]
Retained Earnings [Member]
Noncontrolling Interest [Member]
Stock Options [Member]
Former Affiliated Entity [Member]
Common Stock [Member]
Former Affiliated Entity [Member]
Additional Paid-in Capital [Member]
Former Affiliated Entity [Member]
Treasury Stock [Member]
Former Affiliated Entity [Member]
Stock Options [Member]
Beginning Balances at Dec. 31, 2012 $ 533,547,000 $ 36,947,000 $ 407,206,000 $ (35,762,000) $ 121,097,000 $ 4,059,000          
Beginning Balances, Shares at Dec. 31, 2012   36,946,603   2,327,623              
Net income 35,061,000       29,321,000 5,740,000          
Distributions to noncontrolling interest (7,269,000)         (7,269,000)          
Contributions from noncontrolling interest 3,022,000         3,022,000          
Issuances of restricted stock, Shares       7,298              
Issuances of restricted stock, Value 2,871,000   2,721,000 $ 150,000              
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt, Subsequent Adjustments 17,058,000                    
TEU issuance proceeds, net of issuance costs - 6,000,000 units 120,335,000                    
Issuances from exercises of stock options, net of swaps, Shares   0   53,611       0   136,253  
Issuances from exercises of stock options, net of swaps, Value 683,000 $ 0 66,000 $ 617,000       $ 0 $ (515,000) $ 1,938,000 $ 1,423,000
Shares withheld for payroll taxes, Shares       (59,219)              
Shares withheld for payroll taxes, Value (1,137,000)   (8,000) $ (1,129,000)              
Forfeitures of restricted stock, Shares       (9,986)              
Forfeitures of restricted stock, Value 0   10,000 $ (10,000)              
Share-based compensation 9,911,000   9,911,000                
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock (108,000)   (108,000)                
Ending Balances at Dec. 31, 2013 715,397,000 $ 36,947,000 556,676,000 $ (34,196,000) 150,418,000 5,552,000          
Ending Balances, Shares at Dec. 31, 2013   36,946,603   2,199,666              
Net income 17,088,000       16,583,000 505,000          
Distributions to noncontrolling interest (4,171,000)         (4,171,000)          
Contributions from noncontrolling interest 2,585,000         2,585,000          
Dissolution of noncontrolling interests 1,342,000         1,342,000          
Purchase of noncontrolling interests, net (6,242,000)   (2,969,000)     (3,273,000)          
Issuances of common stock, Shares   0   164,914              
Issuances of common stock, Value 0 $ 0 (2,567,000) $ 2,567,000              
Issuances from exercises of stock options, net of swaps, Shares       45,062       0   60,823  
Issuances from exercises of stock options, net of swaps, Value $ 329,000   (333,000) $ 662,000       $ 0 (43,000) $ 920,000 877,000
Shares withheld for payroll taxes, Shares (55,238)     (55,238)              
Shares withheld for payroll taxes, Value $ (1,043,000)   (4,000) $ (1,039,000)              
Shares repurchased, Shares (1,491,187)     (1,491,187)              
Shares repurchased, Value $ (24,595,000)     $ (24,595,000)              
Forfeitures of restricted stock, Shares       (9,986)              
Forfeitures of restricted stock, Value 0   10,000 $ (10,000)              
Share-based compensation 8,033,000   8,033,000                
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock 142,000   142,000                
Ending Balances at Dec. 31, 2014 709,742,000 $ 36,947,000 558,945,000 $ (55,691,000) 167,001,000 2,540,000          
Ending Balances, Shares at Dec. 31, 2014   36,946,603   3,485,278              
Net income (212,371,000)       (213,047,000) 676,000          
Distributions to noncontrolling interest (701,000)         (701,000)          
Issuances of common stock, Shares       335,611              
Issuances of common stock, Value $ 0   (5,362,000) $ 5,362,000              
Issuances from exercises of stock options, net of swaps, Shares             0     3,999  
Issuances from exercises of stock options, net of swaps, Value                 $ (33,000) $ 64,000 $ 31,000
Shares withheld for payroll taxes, Shares (51,521)     (51,521)              
Shares withheld for payroll taxes, Value $ (762,000)   (1,000) $ (761,000)              
Forfeitures of restricted stock, Shares       (6,579)              
Forfeitures of restricted stock, Value 0   125,000 $ (125,000)              
Share-based compensation 8,576,000   8,576,000                
Tax benefit from exercise of restricted stock units and stock options and vested restricted stock (400,000)   (400,000)                
Ending Balances at Dec. 31, 2015 $ 504,115,000 $ 36,947,000 $ 561,850,000 $ (51,151,000) $ (46,046,000) $ 2,515,000          
Ending Balances, Shares at Dec. 31, 2015   36,946,603   3,203,768              
v3.3.1.900
CONSOLIDATED STATEMENTS OF EQUITY CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical)
Nov. 27, 2013
Unit
6% Tangible Equity Units [Member]  
Units issued 6,000,000
v3.3.1.900
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:      
Consolidated net income (loss) $ (212,371) $ 17,088 $ 35,061
Adjustments:      
Depreciation, depletion and amortization 45,085 41,715 29,980
Change in deferred income taxes 41,261 1,645 5,389
Change in unrecognized tax benefits 0 0 (6,251)
Equity in earnings of unconsolidated ventures (16,008) (8,685) (8,737)
Distributions of earnings of unconsolidated ventures 12,741 5,721 6,360
Share-based compensation 4,246 3,417 16,809
Real estate cost of sales 87,733 84,665 104,899
Dry hole and unproved leasehold impairment costs 67,639 29,528 5,837
Real estate development and acquisition expenditures, net (107,988) (114,694) (106,609)
Reimbursements from utility and improvement districts 15,176 66,047 9,945
Asset impairments 108,184 15,934 1,790
Gain on sale of assets (879) (38,038) (5,161)
Other 4,680 5,887 2,391
Changes in:      
Notes and accounts receivables (978) 10,704 (3,864)
Prepaid expenses and other 3,026 2,180 (795)
Accounts payable and other accrued liabilities (11,868) (4,653) (1,557)
Income taxes (4,553) (11,379) 3,290
Net cash provided by operating activities 35,126 107,082 88,777
Property, equipment, software, reforestation and other (14,690) (16,398) (11,828)
Oil and gas properties and equipment (49,717) (101,145) (96,069)
Acquisition of partner's interest in unconsolidated multifamily venture, net of cash 0 (20,155)  
Acquisition of oil and gas properties 0 (1,100) 0
Investment in unconsolidated ventures (26,349) (14,692) (857)
Proceeds from sale of assets 18,260 21,962 1,333
Return of investment in unconsolidated ventures 12,168 1,797 3,494
Net cash (used for) investing activities (60,328) (129,731) (103,927)
CASH FLOWS FROM FINANCING ACTIVITIES:      
Proceeds from issuance of convertible senior notes, net 0 0 120,795
Proceeds from issuance of senior secured notes, net 0 241,947 0
Proceeds from issuance of tangible equity units, net 0 0 144,998
Payments of debt (58,220) (225,481) (106,076)
Additions to debt 11,463 22,593 43,911
Deferred financing fees (295) (3,217) (438)
Distributions to noncontrolling interests, net (701) (3,146) (7,154)
Purchase of noncontrolling interests 0 (7,971) 0
Exercise of stock options 31 1,206 2,106
Repurchases of common stock 0 (24,595) 0
Payroll taxes on restricted stock and stock options (762) (1,043) (1,137)
Excess income tax benefit from share-based compensation 1 176 91
Net cash (used for) provided by financing activities (48,483) 469 197,096
Net (decrease) increase in cash and cash equivalents (73,685) (22,180) 181,946
Cash and cash equivalents at beginning of year 170,127 192,307 10,361
Cash and cash equivalents at year-end 96,442 170,127 192,307
Cash paid during the year for:      
Interest 27,330 22,936 13,818
Income taxes paid (refunds) (4,077) 18,322 4,955
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:      
Capitalized interest 2,938 1,154 816
Noncontrolling interests $ 0 $ 2,904 2,907
Multi Family Property [Member]      
Acquisition of partner's interest in unconsolidated multifamily venture, net of cash     $ 0
v3.3.1.900
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2015
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements include the accounts of Forestar Group Inc., all subsidiaries, ventures and other entities in which we have a controlling interest. We account for our investment in other entities in which we have significant influence over operations and financial policies using the equity method (we recognize our share of the entities’ income or loss and any preferential returns and treat distributions as a reduction of our investment). We eliminate all material intercompany accounts and transactions. Noncontrolling interests in consolidated pass-through entities are recognized before income taxes.
We prepare our financial statements in accordance with generally accepted accounting principles in the United States, which require us to make estimates and assumptions about future events. Actual results can, and probably will, differ from those we currently estimate. Examples of significant estimates include those related to allocating costs to real estate, measuring long-lived assets for impairment, oil and gas revenue accruals, capital expenditure and lease operating expense accruals associated with our oil and gas production activities, oil and gas reserves and depletion of our oil and gas properties.
Cash and Cash Equivalents
Cash and cash equivalents include cash and other short-term instruments with original maturities of three months or less. At year-end 2015 and 2014, restricted cash was $200,000 and $217,000 and is included in other assets.
Cash Flows
Expenditures for the acquisition and development of single-family and multifamily real estate that we intend to develop for sale are classified as operating activities. Expenditures for the acquisition and development of properties to be held and operated, investment in oil and gas properties and equipment, and business acquisitions are classified as investing activities. Our accrued capital expenditures for unproved leasehold acquisitions and drilling and completion costs at year-end 2015 and 2014 were $7,033,000 and $19,405,000 and are included in other accrued expenses in our consolidated balance sheets. These oil and gas property additions will be reflected as cash used for investing activities in the period the accrued payables are settled.
Capitalized Software
We capitalize purchased software costs as well as the direct internal and external costs associated with software we develop for our own use. We amortize these capitalized costs using the straight-line method over estimated useful lives generally ranging from three to five years. The carrying value of capitalized software was $237,000 at year-end 2015 and $1,188,000 at year-end 2014 and is included in other assets. The amortization of these capitalized costs was $996,000 in 2015, $1,067,000 in 2014 and $1,593,000 in 2013 and is included in general and administrative and operating expenses.
Environmental and Asset Retirement Obligations
We recognize environmental remediation liabilities on an undiscounted basis when environmental assessments or remediation are probable and we can reasonably estimate the cost. We adjust these liabilities as further information is obtained or circumstances change. Our asset retirement obligations are related to the abandonment and site restoration requirements that result from the acquisition, construction and development of our oil and gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income (loss).
The following summarizes the changes in asset retirement obligations:
 
Year-End
 
2015
 
2014
 
(In thousands)
Beginning balance
$
1,807

 
$
1,483

Additions
65

 
314

Property dispositions
(119
)
 
(230
)
Change in estimate
—

 
118

Liabilities settled
(139
)
 
—

Accretion expense
144

 
122

 
$
1,758

 
$
1,807


Fair Value Measurements
Financial instruments for which we did not elect the fair value option include cash and cash equivalents, accounts and notes receivables, other assets, long-term debt, accounts payable and other liabilities. With the exception of long-term notes receivable and debt, the carrying amounts of these financial instruments approximate their fair values due to their short-term nature or variable interest rates.
Goodwill and Other Intangible Assets
We record goodwill when the purchase price of a business acquisition exceeds the estimated fair value of net identified tangible and intangible assets acquired. We do not amortize goodwill or other indefinite lived intangible assets. Instead, we measure these assets for impairment based on the estimated fair values at least annually or more frequently if impairment indicators exist. We perform the annual impairment measurement in the fourth quarter of each year. Intangible assets with finite useful lives are amortized over their estimated useful lives.
In 2015, we performed our annual goodwill impairment evaluation and concluded that goodwill was not impaired as the estimated fair value exceeded the carrying value.
Income Taxes
We provide deferred income taxes using current tax rates for temporary differences between the financial accounting carrying value of assets and liabilities and their tax accounting carrying values. We recognize and value income tax exposures for the various taxing jurisdictions where we operate based on laws, elections, commonly accepted tax positions, and management estimates. We include tax penalties and interest in income tax expense. We provide a valuation allowance for any deferred tax asset that is not likely to be recoverable in future periods.
When we believe a tax position is supportable but the outcome uncertain, we include the item in our tax return but do not recognize the related benefit in our provision for taxes. Instead, we record a reserve for unrecognized tax benefits, which represents our expectation of the most likely outcome considering the technical merits and specific facts of the position. Changes to liabilities are only made when an event occurs that changes the most likely outcome, such as settlement with the relevant tax authority, expiration of statutes of limitations, changes in tax law, or recent court rulings.
Owned Mineral Interests
When we lease our mineral interests to third-party exploration and production entities, we retain a royalty interest and may take an additional participation in production, including a working interest. Mineral interests and working interests related to our owned mineral interests are included in oil and gas properties and equipment on our balance sheet, net of accumulated depletion.
Oil and Gas Properties
We use the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests leased, costs to drill and complete development of oil and gas wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves and if determined incapable of producing commercial quantities of oil and gas these costs are expensed as dry hole costs. At year-end 2014, we had $8,575,000 in capitalized exploratory well costs pending determination of proved reserves, of which $8,454,000 was charged to expense in 2015 with the remaining capitalized based on determination of proved reserves. At year-end 2015, we have no capitalized exploratory well costs pending determination of proved reserves. Exploration costs include dry hole costs, geological and geophysical costs, expired unproved leasehold costs and seismic studies, and are expensed as incurred. Production costs incurred to maintain wells and related equipment are charged to expense as incurred.
Depreciation and depletion of producing oil and gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible drilling and completion costs. Proved reserves are used to compute unit rates for unamortized acquisition of proved leasehold costs. Unit-of-production amortization rates are revised whenever there is an indication of the need for revision but at least once a year and those revisions are accounted for prospectively as changes in accounting estimates.
Impairment of Oil and Gas Properties
We evaluate our oil and gas properties, including facilities and equipment, for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
The assessment of unproved leasehold properties to determine any possible impairment requires significant judgment. We assess our unproved leasehold properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Impairment expense for proved and unproved oil and gas properties are included in costs of oil and gas producing activities.
Operating Leases
We occupy office space in various locations under operating leases. The lease agreements may contain rent escalation clauses, construction allowances and/or contingent rent provisions. We expense operating leases ratably over the shorter of the useful life or the lease term. For scheduled rent escalation clauses, we recognize the base rent expense on a straight-line basis and record the difference between the recognized rent expense and the amounts payable under the lease as deferred lease credits included in other liabilities in the consolidated balance sheets. Deferred lease credits are amortized over the lease term. For construction allowances, we record leasehold improvement assets included in property and equipment in the consolidated balance sheets amortized over the shorter of their economic lives or the lease term. The related deferred lease credits are amortized as a reduction of rent expense over the lease term.
Property and Equipment
We carry property and equipment at cost less accumulated depreciation. We capitalize the cost of significant additions and improvements, and we expense the cost of repairs and maintenance. We capitalize interest costs incurred on major construction projects. We depreciate these assets using the straight-line method over their estimated useful lives as follows:
 
Estimated
 
Year-End
 
Useful Lives
 
2015
 
2014
 
 
 
(In thousands)
Buildings and building improvements
10 to 40 years
 
$
4,044

 
$
4,461

Property and equipment
2 to 10 years
 
12,230

 
14,084

 
 
 
16,274

 
18,545

Less: accumulated depreciation
 
 
(5,542
)
 
(6,918
)
 
 
 
$
10,732

 
$
11,627


Depreciation expense of property and equipment was $1,067,000 in 2015, $903,000 in 2014 and $1,028,000 in 2013.
Real Estate
We carry real estate at the lower of cost or fair value less cost to sell. We capitalize interest costs once development begins, and we continue to capitalize throughout the development period. We also capitalize infrastructure, improvements, amenities, and other development costs incurred during the development period. We determine the cost of real estate sold using the relative sales value method. When we sell real estate from projects that are not finished, we include in the cost of real estate sold estimates of future development costs through completion, allocated based on relative sales values. These estimates of future development costs are reevaluated at least annually, with any adjustments being allocated prospectively to the remaining units available for sale. We receive cash deposits from home builders for purchases of vacant developed lots from community development projects. These earnest money deposits are released to the home builders as lots are developed and sold.
Income producing properties are carried at cost less accumulated depreciation computed using the straight-line method over their estimated useful lives.
We have agreements with utility or improvement districts, principally in Texas, whereby we agree to convey to the district's water, sewer and other infrastructure-related assets we have constructed in connection with projects within their jurisdiction. The reimbursement for these assets ranges from 70 to 90 percent of allowable cost as defined by the district. The transfer is consummated and we receive payment when the districts have a sufficient tax base to support funding of their bonds. The cost we incur in constructing these assets is included in capitalized development costs, and upon collection, we remove the assets from capitalized development costs. We provide an allowance to reflect our past experiences related to claimed allowable development costs.
Impairment of Real Estate Long-Lived Assets
We review real estate long-lived assets held for use for impairment when events or circumstances indicate that their carrying value may not be recoverable. Impairment exists if the carrying amount of the long-lived asset is not recoverable from the undiscounted cash flows expected from its use and eventual disposition. We determine the amount of the impairment loss by comparing the carrying value of the long-lived asset to its estimated fair value. In the absence of quoted market prices, we determine estimated fair value generally based on the present value of future probability weighted cash flows expected from the sale of the long-lived asset. Non-cash impairment charges related to our owned and consolidated real estate assets are included in cost of real estate sales and other.
Revenue
Real Estate
We recognize revenue from sales of real estate when a sale is consummated, the buyer’s initial investment is adequate, any receivables are probable of collection, the usual risks and rewards of ownership have been transferred to the buyer, and we do not have significant continuing involvement with the real estate sold. If we determine that the earnings process is not complete, we defer recognition of any gain until earned. We recognize revenue from hotel room sales and other guest services when rooms are occupied and other guest services have been rendered. We recognize rental revenues from our multifamily properties when earned in accordance with the terms of the respective leases on a straight-line basis for the period of occupancy.
We recognize construction revenues on multifamily projects that we develop as a general contractor. Construction revenues are recognized as costs are incurred plus fixed fee earned. We are reimbursed for costs paid to subcontractors plus we may earn a development and construction management fee on multifamily projects we develop, both of which are included in commercial and income producing properties revenue. On multifamily projects where our fee is based on a fixed fee plus guaranteed maximum price contract, any cost overruns incurred during construction, as compared to the original budget, will reduce the net fee generated on these projects. Any excess cost overruns estimated over the net fee generated are recognized in the period in which they become evident. At year-end 2015, we are not a general contractor on any of the multifamily projects currently under construction and we do not anticipate to be a general contractor on any new multifamily projects.
We exclude from revenue amounts we collect from utility or improvement districts related to the conveyance of water, sewer and other infrastructure related assets. We also exclude from revenue amounts we collect for timber sold on land being developed. These proceeds reduce capitalized development costs. We exclude from revenue amounts we collect from customers that represent sales tax or other taxes that are based on the sale. These amounts are included in other accrued expenses until paid.
Oil and Gas
We recognize revenue as oil and gas is produced and sold. There are a significant amount of oil and gas properties which we do not operate and, therefore, revenue is typically recorded in the month of production based on an estimate of our share of volumes produced and prices realized. We obtain the most current available production data from the operators and price indices for each well to estimate the accrual of revenue. Obtaining production data on a timely basis for some wells is not feasible; therefore we utilize past production receipts and estimated sales price information to estimate accrual of working interest revenue on all other non-operated wells each month. Revisions to such estimates are recorded as actual results become known. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible.
A majority of our sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined upon a percentage of pre-determined and published monthly index price. The terms of these contracts have not had an effect on how we recognize revenue.
We recognize revenue from mineral bonus payments received as a result of leasing our owned mineral interests to others when we have received an executed agreement with the exploration company transferring the rights to any oil or gas it may find and requiring drilling be done within a specified period, the payment has been collected, and we have no obligation to refund the payment. We recognize revenue from delay rentals received if drilling has not started within the specified period and when the payment has been collected. We recognize revenue from mineral royalties when the minerals have been delivered to the buyer, the value is determinable, and we are reasonably sure of collection.
Other Natural Resources
We recognize revenue from timber sales upon passage of title, which occurs at delivery; when the price is fixed and determinable; and we are reasonably sure of collection. We recognize revenue from recreational leases on the straight-line basis over the lease term. We recognize revenue from the sale of water rights or groundwater reservation agreements upon receipt of an executed agreement and payment has been collected and all conditions to the agreement have been met and we have no further performance obligations to meet. The water delivery revenues will be recognized as water is being delivered and metered at the delivery point.
Share-Based Compensation
We use the Black-Scholes option pricing model for stock options, Monte Carlo simulation pricing model for market-leveraged stock units and for stock options with market conditions, grant date fair value for equity-settled awards and period-end fair value for cash-settled awards. We expense share-based awards ratably over the vesting period or earlier based on retirement eligibility.
Timber
We carry timber at cost less the cost of timber cut. We expense the cost of timber cut based on the relationship of the timber carrying value to the estimated volume of recoverable timber multiplied by the amount of timber cut. We include the cost of timber cut in cost of other natural resources in the income statement. We determine the estimated volume of recoverable timber using statistical information and other data related to growth rates and yields gathered from physical observations, models and other information gathering techniques. Changes in yields are generally due to adjustments in growth rates and similar matters and are accounted for prospectively as changes in estimates. We capitalize reforestation costs incurred in developing viable seedling plantations (up to two years from planting), such as site preparation, seedlings, planting, fertilization, insect and wildlife control, and herbicide application. We expense all other costs, such as property taxes and costs of forest management personnel, as incurred. Once the seedling plantation is viable, we expense all costs to maintain the viable plantations, such as fertilization, herbicide application, insect and wildlife control, and thinning, as incurred.
We own directly or through ventures about 89,000 acres of non-core timberland and undeveloped land, primarily in Georgia. The non-cash cost of timber cut and sold is $250,000 in 2015, $371,000 in 2014 and $609,000 in 2013 and is included in depreciation, depletion and amortization in our statement of cash flows.
v3.3.1.900
Pending Accounting Pronouncements
 12 Months Ended
Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Pending Accounting Pronouncements
Pending Accounting Pronouncements
Pending Accounting Standards
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for annual and interim periods beginning after December 15, 2016. In July 2015, the FASB decided to defer the effective date of the new standard by one year. This deferral results in the updated standard being effective after December 15, 2017. We have not yet selected a transition method and we are currently evaluating the effect that the updated standard will have on our earnings, financial position and disclosures.
In January 2015, the FASB issued ASU 2015-01, Income Statement - Extraordinary and Unusual Items (Subtopic 225-20), which eliminates the concept of extraordinary items from U.S. GAAP. The updated standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.
In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis (Topic 810), requiring entities to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. The revised consolidation model: (1) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, (3) affects the consolidation analysis of reporting entities that are involved with VIEs, and (4) provides a scope exception from consolidation guidance for reporting entities with interests in certain legal entities. The updated standard is effective for financial statements issued for annual and interim periods beginning after December 15, 2015. Early adoption is permitted. The updated standard may be applied retrospectively or using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as part of its initiative to reduce complexity in accounting standards. To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update), which allows an entity to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The updated standards are effective for financial statements issued for annual and interim periods beginning after December 15, 2015. The updated standards are not expected to materially impact our financial position or disclosures.
In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40), in order to provide clarification on whether a cloud computing arrangement includes a software license. If a software license is included, the customer should account for the license consistent with its accounting of other software licenses. If a software license is not included, the arrangement should be accounted for as a service contract. The update is effective for reporting periods beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.
In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Updates. The amendments in this update cover a wide range of topics in the codification and are generally categorized as follows: Amendments Related to Differences between Original Guidance and the Codification; Guidance Clarification and Reference Corrections; Simplification; and, Minor Improvements. The amendments are effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The adoption of this standard is not expected to impact our financial position or results of operations.
In November 2015, the FASB issued ASU 2015-17, Income Taxes - Balance Sheet Classification of Deferred Taxes (Subtopic 740). The ASU requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The amendments in this update are effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2016. We do not currently present a classified consolidated balance sheet and therefore this pronouncement will have no impact on our financial statements and related disclosures.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessees to put most leases on their balance sheets but recognize expenses on their income statements in a manner that is similar to today's accounting. This guidance also eliminates today's real estate-specific provisions for all entities. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. This guidance is effective in 2019, and interim periods within that year. Early adoption is permitted. The new leases standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.
v3.3.1.900
Goodwill and Other Intangible Assets
 12 Months Ended
Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]  
Goodwill and Other Intangible Assets
Goodwill and Other Intangible Assets
Carrying value of goodwill and other intangible assets follows:
 
Year-End
 
2015
 
2014
 
(In thousands)
Goodwill
$
61,164

 
$
63,423

Identified intangibles, net
1,964

 
2,708

 
$
63,128

 
$
66,131


Goodwill related to oil and gas properties is $57,290,000 and $59,549,000 at year-end 2015 and 2014. Goodwill associated with our water resources initiatives is $3,874,000 at year-end 2015 and 2014. The change in goodwill for oil and gas properties is related to goodwill allocated to properties sold in 2015.
Identified intangibles include $1,681,000 in indefinite lived groundwater leases associated with our water resources initiatives and $283,000 related to patents with definite lives associated with the Calliope Gas Recovery System, a process to increase natural gas production.
v3.3.1.900
Real Estate
 12 Months Ended
Dec. 31, 2015
Real Estate [Abstract]  
Real Estate
Real Estate
Real estate consists of:
 
Year-End 2015
 
Year-End 2014
 
Carrying Value
 
Accumulated Depreciation
 
Net Carrying Value
 
Carrying Value
 
Accumulated Depreciation
 
Net Carrying Value
 
(In thousands)
Entitled, developed and under development projects
$
352,141

 
$
—

 
$
352,141

 
$
321,273

 
$
—

 
$
321,273

Undeveloped land (includes land in entitlement)
98,181

 
—

 
98,181

 
93,182

 
—

 
93,182

Commercial
 
 
 
 
 
 
 
 
 
 
 
Radisson Hotel & Suites
62,889

 
(29,268
)
 
33,621

 
59,773

 
(29,062
)
 
30,711

Harbor Lakes golf course and country club (a)
—

 
—

 
—

 
2,054

 
(1,508
)
 
546

Income producing properties
 
 
 
 
 
 
 
 
 
 
 
Eleven
53,896

 
(2,861
)
 
51,035

 
53,958

 
(576
)
 
53,382

Midtown (a)
—

 
—

 
—

 
33,293

 
(231
)
 
33,062

Dillon
19,987

 
—

 
19,987

 
15,203

 
—

 
15,203

Music Row
9,947

 
—

 
9,947

 
7,675

 
—

 
7,675

Downtown Edge
12,706

 
—

 
12,706

 
11,856

 
—

 
11,856

West Austin
9,097

 
—

 
9,097

 
8,866

 
—

 
8,866

 
$
618,844

 
$
(32,129
)
 
$
586,715

 
$
607,133

 
$
(31,377
)
 
$
575,756

 _________________________
(a) 
Sold in 2015.
Our estimated cost of assets for which we expect to be reimbursed by utility and improvement districts were $67,554,000 at year-end 2015 and $65,212,000 at year-end 2014, including $22,302,000 at year-end 2015 and $31,913,000 at year-end 2014 related to our Cibolo Canyons project near San Antonio. In 2015, we collected $14,751,000 in reimbursements that were previously submitted to these districts. At year-end 2015, our inception to-date submitted and approved reimbursements for the Cibolo Canyons project were $54,376,000, of which we have collected $34,703,000. These costs are principally for water, sewer and other infrastructure assets that we have incurred and submitted or will submit to utility or improvement districts for approval and reimbursement. We expect to be reimbursed by utility and improvement districts when these districts achieve adequate tax basis or otherwise have funds available to support payment.
In 2014, we received $50,550,000 from Cibolo Canyons special improvement district (CCSID) under 2007 economic development agreements (EDA) related to development of the JW Marriott® Hill Country Resort & Spa (Resort) at our Cibolo Canyons project near San Antonio, of which $46,500,000 was related to CCSID's issuance of $48,900,000 Hotel Occupancy Tax (HOT) and Sales and Use Tax Revenue Bonds. These bonds are obligations solely of CCSID and are payable from HOT and sales and use taxes levied on the Resort by CCSID. To facilitate the issuance of the bonds, we provided a $6,846,000 letter of credit to the bond trustee as security for certain debt service fund obligations in the event CCSID tax collections are not sufficient to support payment of the bonds in accordance with their terms. The letter of credit must be maintained until the earlier of redemption of the bonds or scheduled bond maturity in 2034. We also entered into an agreement with San Antonio Real Estate (SARE), owner of the Resort, to assign SARE’s senior rights under the EDA to us in exchange for consideration provided by us, including a surety bond to be drawn if CCSID tax collections are not sufficient to support ad valorem tax rebates payable to SARE. The surety bond will decrease and gain will be recognized as CCSID makes annual ad valorem tax rebate payments to SARE, which obligation is scheduled to be retired in full by 2020. All future receipts are expected to be recognized as gain in the period collected. We recorded gains of $1,160,000 associated with reduction of surety bond and $425,000 associated with collections from CCSID in 2015. In 2014, we recognized a gain of $6,577,000 associated with bond proceeds after recovery of our full resort investment of $24,067,000, which was included in entitled, developed and under development projects. The surety bond has a balance of $7,850,000 at year-end 2015.
In 2015, we sold Midtown Cedar Hill, a 354-unit multifamily property we developed in Cedar, Hill, Texas for $42,880,000, generating segment earnings of $9,265,000 and $18,473,000 in net proceeds after repaying $24,166,000 in outstanding debt.
In 2014, we acquired full ownership in CJUF III, RH Holdings LP partnership (the Eleven venture), owner of a 257-unit multifamily project in Austin in which we previously held a 25 percent interest, for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000. We accounted for this transaction as a business combination achieved in stages and as a result, we remeasured our equity method investment in the Eleven venture to its acquisition-date fair value of $9,839,000 and recognized the resulting gain of $7,610,000 in real estate segment earnings. At acquisition, we recorded additions to commercial and income producing properties of $53,917,000 and other assets of $992,000 primarily consisting of the estimated fair value of in-place tenant leases of $865,000. In addition, we recorded a working capital deficit of $979,000 and debt of $23,936,000.
As a general contractor on guaranteed maximum price contracts associated with two multifamily venture properties, we recognized charges of $1,543,000 in 2015, $5,111,000 in 2014 and $554,000 in 2013 related to cost overruns.
Depreciation expense related to commercial and income producing properties was $6,810,000 in 2015, $3,319,000 in 2014 and $2,507,000 in 2013 and is included in other operating expense.
v3.3.1.900
Oil and Gas Properties and Equipment, net (Notes)
 12 Months Ended
Dec. 31, 2015
Oil and Gas Properties [Abstract]  
Oil and Gas Properties and Equipment, net
Oil and Gas Properties and Equipment, net
Net capitalized costs, utilizing the successful efforts method of accounting, related to our oil and gas producing activities are as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Unproved leasehold interests
$
19,441

 
$
90,446

Proved oil and gas properties
119,414

 
221,299

Total costs
138,855

 
311,745

Less accumulated depreciation, depletion and amortization
(58,242
)
 
(48,252
)
 
$
80,613

 
$
263,493


We review unproved oil and gas properties for impairment based on our current exploration plans and proved oil and gas properties by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset.
In 2015, we recognized $164,831,000 in non-cash impairment charges of which $107,140,000 related to our proved properties and $57,691,000 on our unproved leasehold interests principally due to a significant decline in oil prices, drilling results, a change in our plans to develop acreage and increased likelihood that non-core oil and gas assets will be sold. In 2014, we recognized $32,665,000 in non-cash impairment charges of which $17,130,000 related to our unproved leasehold interests and $15,535,000 on our proved properties principally due to the significant decline in oil prices, drilling results, a change in our plans to develop acreage and increased likelihood that non-core oil and gas assets will be sold. Impairment charges are included in cost of oil and gas producing activities on our consolidated statements of income (loss) and comprehensive income (loss).
In 2015, we recorded a net loss of $706,000 on the sale of 109,000 net mineral acres leased from others and the disposition of 39 gross (7 net) producing oil and gas wells in Nebraska, Texas, Colorado, North Dakota and Oklahoma for total sales proceeds of $17,800,000.
v3.3.1.900
Investment in Unconsolidated Ventures
 12 Months Ended
Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]  
Investment in Unconsolidated Ventures
Investment in Unconsolidated Ventures
At year-end 2015, we had ownership interests in 20 ventures that we account for using the equity method.
Combined summarized balance sheet information for our ventures accounted for using the equity method follows:
 
Venture Assets
 
Venture Borrowings (a)
 
Venture Equity
 
Our Investment
 
At Year-End
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
242, LLC (b)
$
26,687

 
$
33,021

 
$
—

 
$
6,940

 
$
24,877

 
$
21,789

 
$
11,766

 
$
10,098

CL Ashton Woods, LP (d)
7,654

 
13,269

 
—

 
—

 
6,084

 
11,453

 
3,615

 
6,015

CL Realty, LLC
7,872

 
7,960

 
—

 
—

 
7,662

 
7,738

 
3,831

 
3,869

CREA FMF Nashville LLC (b)
58,002

 
40,014

 
51,028

 
29,660

 
4,291

 
5,987

 
3,820

 
5,516

Elan 99, LLC
34,327

 
10,070

 
14,721

 
1

 
15,838

 
9,643

 
14,255

 
8,679

FMF Littleton LLC
52,528

 
26,953

 
22,499

 
—

 
24,370

 
24,435

 
6,270

 
6,287

FMF Peakview LLC
48,908

 
43,638

 
30,524

 
23,070

 
16,828

 
17,464

 
3,447

 
3,575

FOR/SR Forsyth LLC
6,500

 
—

 
—

 
—

 
6,500

 
—

 
5,850

 
—

HM Stonewall Estates, Ltd. (d)
2,842

 
3,750

 
—

 
669

 
2,842

 
3,081

 
1,294

 
1,752

LM Land Holdings, LP (d)
32,008

 
25,561

 
7,752

 
4,448

 
22,751

 
18,500

 
9,664

 
9,322

MRECV DT Holdings LLC
4,215

 
—

 
—

 
—

 
4,215

 
—

 
3,807

 
—

MRECV Edelweiss LLC
2,237

 
—

 
—

 
—

 
2,237

 
—

 
2,029

 
—

MRECV Juniper Ridge
3,006

 
—

 
—

 
—

 
3,006

 
—

 
2,730

 
—

MRECV Meadow Crossing II LLC
728

 
—

 
—

 
—

 
728

 
—

 
655

 
—

Miramonte Boulder Pass, LLC
12,627

 
—

 
5,869

 
—

 
5,474

 
—

 
5,349

 
—

PSW Communities, LP
—

 
16,045

 
—

 
10,515

 
—

 
4,415

 
—

 
3,924

TEMCO Associates, LLC
5,284

 
11,756

 
—

 
—

 
5,113

 
11,556

 
2,557

 
5,778

Other ventures (e)
4,201

 
8,453

 
2,269

 
26,944

 
1,922

 
(25,614
)
 
1,514

 
190

 
$
309,626

 
$
240,490

 
$
134,662

 
$
102,247

 
$
154,738

 
$
110,447

 
$
82,453

 
$
65,005



Combined summarized income statement information for our ventures accounted for using the equity method follows:
 
Revenues
 
Earnings (Loss)
 
Our Share of Earnings (Loss)
 
For the Year
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
(In thousands)
242, LLC (b)
$
20,995

 
$
5,612

 
$
6,269

 
$
9,588

 
$
2,951

 
$
1,512

 
$
4,919

 
$
1,514

 
$
805

CJUF III, RH Holdings (c)
—

 
2,168

 
120

 
—

 
(956
)
 
(652
)
 
—

 
(956
)
 
(652
)
CL Ashton Woods, LP (d)
9,820

 
5,431

 
9,018

 
3,881

 
1,748

 
2,660

 
5,000

 
2,471

 
4,169

CL Realty, LLC
856

 
1,573

 
1,603

 
424

 
1,068

 
1,028

 
212

 
534

 
514

CREA FMF Nashville LLC (b)
1,227

 
—

 
—

 
(1,696
)
 
(163
)
 
—

 
(1,696
)
 
(163
)
 
—

Elan 99, LLC
—

 
—

 
—

 
(49
)
 
(87
)
 
—

 
(44
)
 
(78
)
 
—

FMF Littleton LLC
120

 
—

 
—

 
(367
)
 
(239
)
 
—

 
(92
)
 
(60
)
 
—

FMF Peakview LLC
2,057

 
4

 
1

 
(1,116
)
 
(410
)
 
(252
)
 
(223
)
 
(83
)
 
(50
)
FOR/SR Forsyth LLC
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

HM Stonewall Estates, Ltd. (d)
3,990

 
1,728

 
2,922

 
1,881

 
613

 
1,082

 
952

 
248

 
452

LM Land Holdings, LP (d)
10,956

 
21,980

 
25,426

 
8,251

 
15,520

 
11,012

 
3,342

 
4,827

 
3,418

MRECV DT Holdings LLC
—

 
—

 
—

 
167

 
—

 
—

 
—

 
—

 
—

MRECV Edelweiss LLC
—

 
—

 
—

 
151

 
—

 
—

 
137

 
—

 
—

MRECV Juniper Ridge
—

 
—

 
—

 
106

 
—

 
—

 
—

 
—

 
—

Miramonte Boulder Pass, LLC
—

 
—

 
—

 
(250
)
 
—

 
—

 
(125
)
 
—

 
—

PSW Communities, LP
29,986

 
—

 
—

 
2,688

 
(86
)
 
—

 
1,169

 
(76
)
 
—

TEMCO Associates, LLC
9,485

 
2,155

 
630

 
2,358

 
494

 
96

 
1,179

 
247

 
48

Other ventures
36,237

 
1,792

 
5,994

 
33,303

 
4,835

 
176

 
1,278

 
260

 
33

 
$
125,729

 
$
42,443

 
$
51,983

 
$
59,320

 
$
25,288

 
$
16,662

 
$
16,008

 
$
8,685

 
$
8,737

_____________________
(a) 
Total includes current maturities of $39,590,000 at year-end 2015, of which $6,798,000 is non-recourse to us, and $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us.
(b) 
Includes unamortized deferred gains on real estate contributed by us to ventures. We recognize deferred gains as income as real estate is sold to third parties. Deferred gains of $1,496,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2015.
(c) 
In 2014, we acquired full ownership in the Eleven venture for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000.
(d) 
Includes unrecognized basis difference of $34,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2015. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.
(e) 
Our investment in other ventures reflects our ownership interests generally ranging from 40 to 75 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.
In 2015, we invested $26,349,000 in these ventures and received $24,909,000 in distributions; in 2014, we invested $14,692,000 in these ventures and received $7,518,000 in distributions; and in 2013, we invested $857,000 in these ventures and received $9,854,000 in distributions. Distributions include both return of investments and distributions of earnings.
We provide construction and development services for some of these ventures for which we receive fees. Fees for these services were $1,856,000 in 2015, $2,275,000 in 2014 and $1,068,000 in 2013 and are included in real estate revenues.
v3.3.1.900
Receivables
 12 Months Ended
Dec. 31, 2015
Receivables [Abstract]  
Receivables
Receivables
Receivables consist of:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Funds held by qualified intermediary for potential 1031 like-kind exchange
$
14,703

 
$
—

Oil and gas revenue accruals
3,745

 
7,293

Other receivables and accrued interest
2,448

 
6,505

Other loans secured by real estate, average interest rate of 11.31% at year-end 2015 and 4.41% at year-end 2014
2,130

 
1,737

Oil and gas joint interest billing receivables
867

 
5,738

Loan secured by real estate
—

 
3,574

 
23,893

 
24,847

Allowance for bad debts
(237
)
 
(258
)
 
$
23,656

 
$
24,589


In 2015, funds held by qualified intermediary are related to proceeds received from selling 6,915 acres of undeveloped land pending completion of a potential like-kind exchange.
In 2011, we acquired a non-performing loan that was secured by a lien on developed and undeveloped real estate located near Houston designated for single-family residential and commercial development. In 2015, the loan was paid in full and we received principal payments of $4,394,000 and interest payments of $49,000.
Estimated accretable yield is as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Beginning of year
$
839

 
$
8,908

Change in accretable yield due to change in timing of estimated cash flows
30

 
(166
)
Interest income recognized
(869
)
 
(7,903
)
 
$
—

 
$
839


Other loans secured by real estate generally are secured by a deed of trust and due within three years.
v3.3.1.900
Debt
 12 Months Ended
Dec. 31, 2015
Debt Disclosure [Abstract]  
Debt
Debt
Debt consists of:
 
At Year-End
 
2015
 
2014
 
(In thousands)
8.50% senior secured notes due 2022
230,560

 
250,000

3.75% convertible senior notes due 2020, net of discount
106,762

 
103,194

6.00% tangible equity units, net of discount
8,768

 
17,154

Secured promissory notes — average interest rates of 3.42% at year-end 2015 and 3.17% at year-end 2014
15,400

 
15,400

Other indebtedness due through 2018 at variable and fixed interest rates ranging from 2.19% to 5.50%
28,292

 
46,996

 
$
389,782

 
$
432,744


At year-end 2015, our senior secured credit facility provides for a $300,000,000 revolving line of credit maturing May 15, 2017. The revolving line of credit may be prepaid at any time without penalty. The revolving line of credit includes a $100,000,000 sublimit for letters of credit, of which $15,899,000 is outstanding at year-end 2015. Total borrowings under our senior secured credit facility (including the face amount of letters of credit) may not exceed a borrowing base formula. At year-end 2015, we had $284,101,000 in net unused borrowing capacity under our senior credit facility.
Under the terms of our senior secured credit facility, at our option, we can borrow at LIBOR plus 4.0 percent or at the alternate base rate plus 3.0 percent. The alternate base rate is the highest of (i) KeyBank National Association’s base rate, (ii) the federal funds effective rate plus 0.5 percent or (iii) 30 day LIBOR plus 1 percent. Borrowings under the senior secured credit facility are or may be secured by (a) mortgages on the timberland, high value timberland and portions of raw entitled land, as well as pledges of other rights including certain oil and gas operating properties, (b) assignments of current and future leases, rents and contracts, (c) a security interest in our primary operating account, (d) a pledge of the equity interests in current and future material operating subsidiaries and most of our majority-owned joint venture interests, or if such pledge is not permitted, a pledge of the right to distributions from such entities, and (e) a pledge of certain reimbursements payable to us from special improvement district tax collections in connection with our Cibolo Canyons project. The senior secured credit facility provides for releases of real estate and other collateral provided that borrowing base compliance is maintained.
Our debt agreements contain financial covenants customary for such agreements including minimum levels of interest coverage and limitations on leverage. In third quarter 2015, we received a waiver of the consolidated tangible net worth maintenance covenant requirement of our senior credit facility. At year-end 2015, our tangible net worth requirement was $379,044,000 plus 85 percent of the aggregate net proceeds received by us from any equity offering, plus 75 percent of all positive net income, on a cumulative basis. At year-end 2015, there were no adjustments to the tangible net worth requirement for net proceeds from equity offerings or positive net income on a cumulative basis. The tangible net worth requirement is recalculated on a quarterly basis.
On December 30, 2015, we amended our senior secured credit facility to reduce the interest coverage ratio from 2.50:1.0 to 2.25:1.0 for the quarters ending December 31, 2015 and March 31, 2016. Thereafter, the interest coverage ratio returns to 2.50:1.0. At year-end 2015, we were in compliance with the financial covenants of these agreements.
We may elect to make distributions to stockholders so long as the total leverage ratio is less than 40 percent, the interest coverage ratio is greater than 3.0:1.0 and available liquidity is not less than $125,000,000. Effective December 30, 2015, the senior secured credit facility was amended to provide that we may make distributions in an aggregate amount not to exceed $50,000,000 to be funded from up to 65% of the net proceeds from sales of multifamily properties and non-core assets, such as the Radisson Hotel & Suites in Austin, and any oil and gas properties. The amendment provides us the flexibility to repurchase stock or pay a special dividend should our Board of Directors determine that we should do so, though no such decisions have been made at this time.
In 2014, we issued $250,000,000 aggregate principal of 8.50% Senior Secured Notes due 2022 (Notes). The Notes will mature on June 1, 2022 and interest on the Notes is payable semiannually at a rate of 8.5 percent per annum in arrears. Net proceeds from issuance of the Notes were used to repay our $200,000,000 senior secured term loan. In December 2015, we purchased $19,440,000 principal amount of Notes at 97% of face value, resulting in a gain of $589,000 on the early extinguishment of the retired Notes, offset by the write-off of unamortized debt issuance costs of $506,000 allocated to the retired Notes.
In 2013, we issued $125,000,000 aggregate principal amount of 3.75% convertible senior notes due 2020 (Convertible Notes). Interest on the Convertible Notes is payable semiannually at a rate of 3.75 percent per annum and they mature on March 1, 2020. The Convertible Notes have an initial conversion rate of 40.8351 per $1,000 principal amount. The initial conversion rate is subject to adjustment upon the occurrence of certain events. Prior to November 1, 2019, the Convertible Notes are convertible only upon certain circumstances, and thereafter are convertible at any time prior to the close of business on the second scheduled trading day prior to maturity. If converted, holders will receive cash, shares of our common stock or a combination thereof at our election. We intend to settle the principal amount of the Convertible Notes in cash upon conversion, with any excess conversion value to be settled in shares of our common stock. At year-end 2015, unamortized debt discount of our Convertible Notes was $18,238,000.
In 2013, we issued $150,000,000 aggregate principal amount of 6.00% tangible equity units (Units). The total offering was 6,000,000 Units, including 600,000 exercised by the underwriters, each with a stated amount of $25.00. Each Unit is comprised of (i) a prepaid stock purchase contract to be settled by delivery of a number of shares of our common stock, par value $1.00 per share to be determined pursuant to a purchase contract agreement, and (ii) a senior amortizing note due December 15, 2016 that has an initial principal amount of $4.2522, bears interest at a rate of 4.50% per annum and has a final installment payment date of December 15, 2016. The actual number of shares we may issue upon settlement of the stock purchase contract will be between 6,547,800 shares (the minimum settlement rate) and 7,857,000 shares (the maximum settlement rate) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.
At year-end 2015, secured promissory notes include a $15,400,000 loan collateralized by a 413 guest room hotel located in Austin with a carrying value of $33,621,000.
At year-end 2015, other indebtedness principally include a senior secured construction loan for one multifamily property for $23,936,000 related to a 257-unit multifamily project in Austin with a carrying value of $51,035,000 at year-end 2015. The decrease in other indebtedness is principally related to the sale of Midtown Cedar Hill and the payoff of the related debt of $24,166,000.
At year-end 2015 and 2014, we have $11,034,000 and $15,168,000 in unamortized deferred fees which are included in other assets. Amortization of deferred financing fees was $4,002,000 in 2015, $3,845,000 in 2014 and $3,050,000 in 2013 and is included in interest expense.
Debt maturities during the next five years are: 2016 — $27,973,000; 2017 — $551,000; 2018 — $23,936,000; 2019 — $0; 2020 — $106,762,000 and thereafter — $230,560,000.
v3.3.1.900
Fair Value
 12 Months Ended
Dec. 31, 2015
Fair Value Disclosures [Abstract]  
Fair Value
Fair Value
Fair value is the exchange price that would be the amount received for an asset or paid to transfer a liability in an orderly transaction between market participants. In arriving at a fair value measurement, we use a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable. The three levels of inputs used to establish fair value are the following:
•
Level 1 — Quoted prices in active markets for identical assets or liabilities;
•
Level 2 — Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and
•
Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
We elected not to use the fair value option for cash and cash equivalents, accounts receivable, other current assets, variable debt, accounts payable and other current liabilities. The carrying amounts of these financial instruments approximate their fair values due to their short-term nature or variable interest rates. We determine the fair value of fixed rate financial instruments using quoted prices for similar instruments in active markets.
Information about our fixed rate financial instruments not measured at fair value follows:
 
Year-End 2015
 
Year-End 2014
 
 
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
Valuation
Technique
 
(In thousands)
Recurring Fair Value Measurements:
 
 
 
 
 
 
 
 
 
Loan secured by real estate
$
—

 
$
—

 
$
3,574

 
$
4,859

 
Level 2
Fixed rate debt
$
(346,090
)
 
$
(321,653
)
 
$
(370,348
)
 
$
(359,131
)
 
Level 2

Non-financial assets measured at fair value on a non-recurring basis principally include real estate assets, proved oil and gas properties, goodwill and intangible assets, which are measured for impairment.
In 2015, we recognized proved properties oil and gas non-cash impairment charges of $107,140,000 primarily in North Dakota, Nebraska and Kansas principally due to a significant decline in oil and gas prices and the likelihood these assets will be sold. The fair value of these properties was determined using Level 3 inputs and income valuation method based on estimated future commodity prices and our various operational assumptions. In instances where a third party bid was received for a combination of proved and unproved properties, an estimate of the allocation of bid prices was performed and fair value was adjusted accordingly. Included in proved oil and gas non-cash impairments were impairments associated with properties that were sold in fourth quarter 2015. In addition, in 2015 we recognized impairments of $57,691,000 for unproved leasehold interests as a result of continued decline in oil prices and our current plans to only allocate capital to these non-core assets to preserve values and optionality for ultimate sale. Fair value of certain unproved leasehold interests that were impaired were based on market comparables or where a third party bid was received for a combination of proved and unproved properties, an estimate of the allocation of fair value was performed which reduced the carrying value of these leasehold interests.
In 2015 and 2014, certain real estate assets were remeasured and reported at fair value due to events or circumstances that indicated the carrying value may not be recoverable. We determined estimated fair value based on the present value of future probability weighted cash flows expected from the sale of the long-lived asset or based on a third party appraisal of current value. As a result, we recognized non-cash asset impairment charges of $1,044,000 in 2015 associated with a residential development with golf course and country club property near Fort Worth which was sold in April 2015, one owned project near Atlanta where the remaining lots were sold in August 2015 and one owned entitled project in Atlanta. We had $399,000 non-cash impairment charges in 2014 associated with two owned entitled projects.
 
Year-End 2015
 
Year-End 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Non-recurring Fair Value Measurements:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved oil and gas properties
$
—

 
$
—

 
$
39,000

 
$
39,000

 
$
—

 
$
—

 
$
3,655

 
$
3,655

Unproved leasehold interests
$
—

 
$
—

 
$
18,219

 
$
18,219

 
$
—

 
$
—

 
$
—

 
$
—

Real estate
$
—

 
$
—

 
$
641

 
$
641

 
$
—

 
$
—

 
$
970

 
$
970
v3.3.1.900
Capital Stock
 12 Months Ended
Dec. 31, 2015
Equity [Abstract]  
Capital Stock
Capital Stock
In 2015, we accelerated the expiration date of our shareholder rights plan from December 11, 2017 to March 13, 2015, resulting in termination of the plan.
Please read Note 8 — Debt and Note 11 — Net Income (Loss) per Share for information about shares of common stock that could be issued under our 3.75% convertible senior notes due 2020 and our 6.00% tangible equity units.
Please read Note 17 — Share-Based and Long-Term Incentive Compensation for information about additional shares of common stock that could be issued under terms of our share-based compensation plans.
At year-end 2015, personnel of former affiliates held options to purchase 500,798 shares of our common stock. The options have a weighted average exercise price of $28.62 and a weighted average remaining contractual term of one year. At year-end 2015, the options have an aggregate intrinsic value of $0.
In 2015, we did not repurchase shares of our common stock. In 2014, we repurchased 1,491,187 shares of our common stock for $24,595,000. We have repurchased 3,493,332 shares of our common stock for $54,159,000 since we announced our 2009 strategic initiative of repurchasing up to 20 percent or up to 7,000,000 shares of our common stock.
v3.3.1.900
Net Income per Share
 12 Months Ended
Dec. 31, 2015
Earnings Per Share [Abstract]  
Net Income (Loss) per Share
Net Income (Loss) per Share
Basic and diluted earnings (loss) per share are computed using the two-class method. The two-class method is an earnings allocation formula that determines net income per share for each class of common stock and participating security. We have determined that our 6.00% tangible equity units are participating securities. Per share amounts are computed by dividing earnings available to common shareholders by the weighted average shares outstanding during each period.
The computations of basic and diluted earnings (loss) per share are as follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Numerator:
 
 
 
 
 
Consolidated net income (loss)
$
(212,371
)
 
$
17,088

 
$
35,061

Less: Net (income) attributable to noncontrolling interest
(676
)
 
(505
)
 
(5,740
)
Income (loss) available for diluted earnings per share
$
(213,047
)
 
$
16,583

 
$
29,321

Less: Undistributed net income allocated to participating securities
—

 
(3,018
)
 
(585
)
Income (loss) available to common shareholders for basic earnings per share
$
(213,047
)
 
$
13,565

 
$
28,736

 
 
 
 
 
 
Denominator:
 
 
 
 
 
Weighted average common shares outstanding — basic
34,266

 
35,317

 
35,365

Weighted average common shares upon conversion of participating securities (a)
—

 
7,857

 
835

Dilutive effect of stock options, restricted stock and equity-settled awards
—

 
422

 
613

Total weighted average shares outstanding — diluted
34,266

 
43,596

 
36,813

Anti-dilutive awards excluded from diluted weighted average shares outstanding
10,864

 
2,238

 
1,803


 _____________________
(a)
Our earnings per share calculation reflects the weighted average shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units, issued in 2013.
The actual number of shares we may issue upon settlement of the stock purchase contract will be between 6,547,800 shares (the minimum settlement rate) and 7,857,000 shares (the maximum settlement rate) based on the applicable market value, as defined in the purchase contract agreement associated with issuance of the Units.
We intend to settle the principal amount of the Convertible Notes in cash upon conversion with any excess conversion value to be settled in shares of our common stock. Therefore, only the amount in excess of the par value of the Convertible Notes will be included in our calculation of diluted net income per share using the treasury stock method. As such, the Convertible Notes have no impact on diluted net income per share until the price of our common stock exceeds the conversion price of the Convertible Notes of $24.49. The average price of our common stock in 2015 did not exceed the conversion price which resulted in no additional diluted outstanding shares.
v3.3.1.900
Income Taxes
 12 Months Ended
Dec. 31, 2015
Income Tax Disclosure [Abstract]  
Income Taxes
Income Taxes
Income tax (expense) benefit consists of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Current tax provision:
 
 
 
 
 
U.S. Federal
$
8,579

 
$
(5,444
)
 
$
(6,004
)
State and other
47

 
(1,569
)
 
(2,066
)
 
8,626

 
(7,013
)
 
(8,070
)
Deferred tax provision:
 
 
 
 
 
U.S. Federal
(38,366
)
 
(2,772
)
 
1,148

State and other
(2,895
)
 
1,128

 
(286
)
 
(41,261
)
 
(1,644
)
 
862

Income tax (expense) benefit
$
(32,635
)
 
$
(8,657
)
 
$
(7,208
)

A reconciliation of the federal statutory rate to the effective income tax rate on continuing operations follows:
 
For the Year
 
2015
 
2014
 
2013
Federal statutory rate (benefit)
(35
%)
 
35
 %
 
35
 %
State, net of federal benefit
(1
)
 
1

 
4

Valuation allowance
54

 
—

 
—

Recognition of previously unrecognized tax benefits
—

 
—

 
(15
)
Noncontrolling interests
—

 
—

 
(5
)
Goodwill
—

 
1

 
—

Charitable contributions
—

 
(1
)
 
—

Oil and gas percentage depletion
—

 
(2
)
 
(2
)
Effective tax rate
18
 %
 
34
 %
 
17
 %

Our 2015 effective tax rate includes a 54 percent detriment from a valuation allowance recorded against our deferred tax asset and our 2013 effective tax rate includes a 15 percent benefit from recognition of $6,326,000 of previously unrecognized tax benefits upon lapse of the statute of limitations for a previously reserved tax position.
Significant components of deferred taxes are:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Deferred Tax Assets:
 
 
 
Real estate
$
69,594

 
$
79,244

Employee benefits
15,752

 
17,352

Net operating loss carryforwards
13,827

 
3,012

Oil and gas properties
5,510

 
—

AMT credits
3,620

 
—

Income producing properties
—

 
364

Oil and gas percentage depletion carryforwards
3,616

 
3,471

Accruals not deductible until paid
911

 
1,111

Other assets
139

 
—

Gross deferred tax assets
112,969

 
104,554

Valuation allowance
(97,068
)
 
(384
)
Deferred tax asset net of valuation allowance
15,901

 
104,170

Deferred Tax Liabilities:
 
 
 
Oil and gas properties
—

 
(49,905
)
Undeveloped land
(7,588
)
 
(4,937
)
Convertible debt
(6,516
)
 
(7,816
)
Income producing properties
(2,257
)
 
—

Timber
(577
)
 
(888
)
Gross deferred tax liabilities
(16,938
)
 
(63,546
)
Net Deferred Tax Asset (Liability)
$
(1,037
)
 
$
40,624


At year-end 2015, we had approximately $37,500,000 and $43,900,000 of federal and state net operating loss carryforwards. Approximately $7,500,000 of the federal and $2,400,000 of the state net operating loss carryforwards were from our acquisition of Credo at third quarter 2012 and are subject to certain limitations. If not utilized, the federal carryforwards will expire in 2035 and the state carryforwards will expire in 2016 to 2035. We had approximately $9,800,000 of oil and gas percentage depletion carryforwards of which approximately $9,200,000 were a result of our acquisition of Credo and are subject to certain limitations. The percentage depletion and AMT credit carryforwards do not expire.
Our deferred tax asset on oil and gas properties includes the effect of impairments recorded in 2015.
Goodwill associated with our acquistion of Credo is not deductible for income tax purposes.
The increase in valuation allowance for the year 2015 was principally due to oil and gas impairments. In determining our valuation allowance, we assessed available positive and negative evidence to estimate whether sufficient future taxable income would be generated to permit use of the existing deferred tax asset. A significant piece of objective evidence was the cumulative loss incurred over the three-year period ended December 31, 2015, principally driven by impairments of oil and gas properties. Such evidence limited our ability to consider other subjective evidence, such as our projected future taxable income.
The amount of deferred tax asset considered realizable could be adjusted if negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence, such as our projected future taxable income.
We file income tax returns in the U.S. federal jurisdiction and in various state jurisdictions. We are no longer subject to U.S. federal income tax examinations for years before 2012 and state examinations for years before 2011.
A reconciliation of the beginning and ending amount of tax benefits not recognized for book purposes is as follows:
 
At Year-End
 
2015
 
2014
 
2013
 
(In thousands)
Balance at beginning of year
$
—

 
$
—

 
$
5,831

Reductions for tax positions of prior years
—

 
—

 
—

Reductions due to lapse of statute of limitations
—

 
—

 
(5,831
)
Balance at end of year that would affect the annual effective tax rate if recognized
$
—

 
$
—

 
$
—


We recognize interest accrued related to unrecognized tax benefits in income tax expense. In 2015, 2014 and 2013, we recognized approximately $0, $0 and $75,000 in interest expense. At year-end 2015 and 2014, we have no accrued interest or penalties.
v3.3.1.900
Litigation and Environmental Contingencies
 12 Months Ended
Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]  
Litigation and Environmental Contingencies
Litigation and Environmental Contingencies
Litigation
We are involved in various legal proceedings that arise from time to time in the ordinary course of doing business and believe that adequate reserves have been established for any probable losses. We do not believe that the outcome of any of these proceedings should have a significant adverse effect on our financial position, long-term results of operations or cash flows. It is possible, however, that charges related to these matters could be significant to our results or cash flows in any one accounting period.
On October 4, 2014, James Huffman, a former director and CEO of CREDO Petroleum Corporation (Credo), which we acquired in 2012 and is now known as Forestar Petroleum Corporation, filed Huffman vs. Forestar Petroleum Corporation, Case Number 14CV33811, Civil Division, District Court for the City and County of Denver, Colorado. Prior to his retirement from Credo, Huffman participated in an employee compensation program under which he received overriding royalty interests (ORRI) in certain leases or wells in which Credo had an interest. Huffman claims entitlement to ORRI on nearly all North Dakota leases, none of which were assigned by Credo to Huffman prior to his retirement, and to ORRI on several Kansas and Nebraska leases. Huffman is seeking to have ORRI assigned to him. We believe Huffman’s claims are without merit and are vigorously defending the case. We are unable to estimate a possible loss or range of possible loss for this matter because of, among other factors, (i) significant unresolved questions of fact, including the time period covered by Huffman’s claims, (ii) discovery remaining to be conducted by both parties; (iii) impact of our counterclaims against Huffman, and (iv) any other factors that may have a material effect on the litigation.
Environmental
Environmental remediation liabilities arise from time to time in the ordinary course of doing business, and we believe we have established adequate reserves for any probable losses that we can reasonably estimate. We own 288 acres near Antioch, California, portions of which were sites of a former paper manufacturing operation that are in remediation. We have received certificates of completion on all but one 80 acre tract, a portion of which includes subsurface contamination. In 2015, we increased our reserves for environmental remediation by $689,000 due to additional testing and remediation requirements by state regulatory agencies. At year-end 2015, our accrued liability to complete remediation activities was $682,000, which is included in other accrued expenses. It is possible that remediation or monitoring activities could be required in addition to those included within our estimate, but we are unable to determine the scope, timing or extent of such activities.
We have asset retirement obligations related to the abandonment and site restoration requirements that result from the acquisition, construction and development of oil and gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income (loss) and comprehensive income (loss). At year-end 2015, our asset retirement obligation was $1,758,000, which is included in other liabilities.
v3.3.1.900
Commitments and Other Contingencies
 12 Months Ended
Dec. 31, 2015
Leases [Abstract]  
Commitments and Other Contingencies
Commitments and Other Contingencies
We lease facilities and equipment under non-cancelable long-term operating lease agreements. In addition, we have various obligations under other office space and equipment leases of less than one year. Rent expense on facilities and equipment was $3,872,000 in 2015, $2,617,000 in 2014 and $2,374,000 in 2013. Future minimum rental commitments under non-cancelable operating leases having a remaining term in excess of one year are: 2016 — $2,696,000; 2017 — $2,738,000; 2018 — $1,706,000; 2019 — $170,000; 2020 — $174,000 and thereafter —$59,000.
We have two years remaining on groundwater leases of about 20,000 acres. At year-end 2015, the remaining contractual obligation for these groundwater leases is $1,009,000.
We lease approximately 32,000 square feet of office space in Austin, Texas, which we occupy as our corporate headquarters. The remaining contractual obligation for this lease is $4,212,000. We also lease office space in several other locations in support of our business operations with approximately 21,000 square feet in Denver, Colorado. The total remaining contractual obligations for these leases is $2,269,000.
We may provide performance bonds and letters of credit on behalf of certain ventures that would be drawn on due to failure to satisfy construction obligations as general contractor or for failure to timely deliver streets and utilities in accordance with local codes and ordinances.

Unallocated Severance-related Costs
In connection with the departures of our former CEO and CFO in September 2015, we recorded severance-related charges of $3,314,000 which are included in general and administrative expense on our consolidated statements of income (loss) and comprehensive income (loss). We paid $2,732,000 of these severance-related charges in fourth quarter 2015 with the balance to be paid in 2016.

Oil and Gas Restructuring Costs
In connection with review of strategic alternatives with respect to our oil and gas business and the determination it is a non-core business that we will be exiting over time, we offered retention bonuses to key personnel provided they remained our employees through December 2015. We expensed retention bonus costs over the retention period. In 2015, we incurred severance expenses related to staff reductions, paid a portion of the 2014 accrual under written severance agreements and incurred costs associated with closure of our Fort Worth office. Office closure costs include a $1,750,000 lease termination charge and $391,000 for write off of leasehold improvements which were partially offset by a deferred lease credit of $364,000. These restructuring costs are included in other operating expense on our consolidated statements of income (loss) and comprehensive income (loss). We may incur additional costs related to our initiatives to exit non-core oil and gas assets.
The following table summarizes activity related to liabilities associated with our oil and gas restructuring activities in 2015:
 
Employee-Related Costs
 
Lease Termination Charge
 
Total
 
(In thousands)
Balance at year-end 2014
$
(2,367
)
 
$
—

 
$
(2,367
)
Additions
(2,047
)
 
(1,750
)
 
(3,797
)
Payments
3,365

 
1,750

 
5,115

Balance at year-end 2015
$
(1,049
)
 
$
—

 
$
(1,049
)
v3.3.1.900
Segment Information
 12 Months Ended
Dec. 31, 2015
Segment Reporting [Abstract]  
Segment Information
Segment Information
We manage our operations through three business segments: real estate, oil and gas and other natural resources. Real estate secures entitlements and develops infrastructure on our lands for single-family residential and mixed-use communities, and manages our undeveloped land, commercial and income producing properties, primarily a hotel and our multifamily properties. Oil and gas is an independent oil and gas exploration, development and production operation and manages our owned and leased mineral interests. Other natural resources manages our timber, recreational leases and water resource initiatives.
We evaluate performance based on segment earnings (loss) before unallocated items and income taxes. Segment earnings (loss) consist of operating income, equity in earnings (loss) of unconsolidated ventures, gain on sales of assets, interest income on loans secured by real estate and net (income) loss attributable to noncontrolling interests. Items not allocated to our business segments consist of general and administrative expense, share-based and long-term incentive compensation, gain on sale of strategic timberland, interest expense and other corporate non-operating income and expense. The accounting policies of the segments are the same as those described in Note 1 — Summary of Significant Accounting Policies. Our revenues are derived from our U.S. operations and all of our assets are located in the U.S. In 2015, 2014 and 2013, no single customer accounted for more than 10 percent of our total revenues, other than the customers associated with the sale of our multifamily projects Midtown Cedar Hill and Promesa in 2015 and 2013.
 
Real
Estate
 
Oil and Gas
 
Other Natural
Resources
 
Items Not
Allocated to
Segments
 
 
Total
 
(In thousands)
For the year or at year-end 2015
 
 
 
 
 
 
 
 
 
 
Revenues
$
202,830

 
$
52,939

 
$
6,652

 
$
—

  
 
$
262,421

Depreciation, depletion and amortization
7,605

 
28,774

 
540

 
8,166

  
 
45,085

Equity in earnings of unconsolidated ventures
15,582

 
275

 
151

 
—

  
 
16,008

Income (loss) before taxes
67,678

 
(184,396
)
 
(608
)
 
(63,086
)
(a) 
 
(180,412
)
Total assets
691,406

 
144,436

 
19,106

 
125,565

  
 
980,513

Investment in unconsolidated ventures
82,453

 
—

 
—

 
—

  
 
82,453

Capital expenditures (b)
13,644

 
49,776

 
745

 
242

  
 
64,407

For the year or at year-end 2014
 
 
 
 
 
 
 
 
 
 
Revenues
$
213,112

 
$
84,300

 
$
9,362

 
$
—

  
 
$
306,774

Depreciation, depletion and amortization
3,741

 
29,442

 
497

 
8,035

  
 
41,715

Equity in earnings of unconsolidated ventures
8,068

 
586

 
31

 
—

  
 
8,685

Income (loss) before taxes
96,906

 
(22,686
)
 
5,499

 
(54,479
)
(a) 
 
25,240

Total assets
654,774

 
342,703

 
22,531

 
238,191

  
 
1,258,199

Investment in unconsolidated ventures
65,005

 
—

 
—

 
—

  
 
65,005

Capital expenditures (b)
28,980

 
103,385

 
5,817

 
616

  
 
138,798

For the year or at year-end 2013
 
 
 
 
 
 
 
 
 
 
Revenues
$
248,011

 
$
72,313

 
$
10,721

 
$
—

  
 
$
331,045

Depreciation, depletion and amortization
3,117

 
19,552

 
651

 
6,660

  
 
29,980

Equity in earnings of unconsolidated ventures
8,089

 
592

 
56

 
—

  
 
8,737

Income (loss) before taxes
68,454

 
18,859

 
6,507

 
(57,291
)
(a) 
 
36,529

Total assets
582,802

 
312,553

 
23,478

 
253,319

  
 
1,172,152

Investment in unconsolidated ventures
41,147

 
—

 
—

 
—

  
 
41,147

Capital expenditures (b)
7,265

 
97,696

 
2,720

 
216

  
 
107,897

 _____________________
(a) 
Items not allocated to segments consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
General and administrative expense
$
(24,802
)
 
$
(21,229
)
 
$
(20,597
)
Share-based and long-term incentive compensation expense
(4,474
)
 
(3,417
)
 
(16,809
)
Interest expense
(34,066
)
 
(30,286
)
 
(20,004
)
Other corporate non-operating income
256

 
453

 
119

 
$
(63,086
)
 
$
(54,479
)
 
$
(57,291
)

(b) 
Consists of expenditures for oil and gas properties and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.
v3.3.1.900
Variable Interest Entities
 12 Months Ended
Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Variable Interest Entities
Variable Interest Entities
We participate in real estate ventures for the purpose of acquiring and developing residential, multifamily and mixed-use communities in which we may or may not have a controlling financial interest. Generally accepted accounting principles require consolidation of VIEs in which an enterprise has a controlling financial interest and is the primary beneficiary. A controlling financial interest will have both of the following characteristics: (a) the power to direct the VIE activities that most significantly impact economic performance and (b) the obligation to absorb the VIE losses and right to receive benefits that are significant to the VIE. We examine specific criteria and use judgment when determining whether we are the primary beneficiary and must consolidate a VIE. We perform this review initially at the time we enter into venture agreements and continuously reassess to see if we are the primary beneficiary of a VIE.
At year-end 2015, we have two VIEs. We account for these VIEs using the equity method and we are not the primary beneficiary. Although we have certain rights regarding major decisions, we do not have the power to direct the activities that are most significant to the economic performance of these VIEs. At year-end 2015, these VIEs have total assets of $62,187,000, substantially all of which represent developed and undeveloped real estate and total liabilities of $55,989,000, which includes $2,269,000 of borrowings classified as current maturities. These amounts are included in the summarized balance sheet information for ventures accounted for using the equity method in Note 6 — Investment in Unconsolidated Ventures. At year-end 2015, our investment is $5,322,000 and is included in investment in unconsolidated ventures. In 2015, we contributed $148,000 to these VIEs. Our maximum exposure to loss related to one of these VIEs is estimated at $3,780,000, which exceeds our investment as we have a nominal general partner interest and could be held responsible for its liabilities. The maximum exposure to loss represents the maximum loss that we could be required to recognize assuming all the ventures’ assets (principally real estate) are worthless, without consideration of the probability of a loss or of any actions we may take to mitigate any such loss.
In 2014, we acquired our partner's noncontrolling interests in the Lantana partnerships for $7,971,000. Prior to acquisition of the noncontrolling interests, we were the primary beneficiary of all but one of the Lantana partnerships which were VIEs and consolidated in our financial statements. We adjusted the carrying amount of noncontrolling interests to reflect the change in our ownership interest in the partnerships. The difference between the consideration paid and the carrying amount of the noncontrolling interests acquired is recognized as an adjustment to additional paid in capital attributable to Forestar, net of deferred taxes of $1,729,000.
v3.3.1.900
Share-Based Compensation
 12 Months Ended
Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]  
Share-Based and LongTerm incentive Compensation
Share-Based and Long-Term Incentive Compensation
Share-based and long-term incentive compensation expense consists of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Cash-settled awards
$
(3,127
)
 
$
(3,710
)
 
$
7,774

Equity-settled awards
5,026

 
5,168

 
4,281

Restricted stock
(8
)
 
(25
)
 
538

Stock options
2,355

 
1,984

 
4,216

Total share-based compensation
$
4,246

 
$
3,417

 
$
16,809

Deferred cash
228

 
—

 
—

 
$
4,474

 
$
3,417

 
$
16,809


Share-based and long-term incentive compensation expense is included in:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
General and administrative
$
2,451

 
$
1,001

 
$
7,779

Other operating
2,023

 
2,416

 
9,030

 
$
4,474

 
$
3,417

 
$
16,809


Excluded from share-based compensation expense in the table above are fees earned by directors in the amount of $1,203,000 for 2015, $906,000 for 2014 and $876,000 for 2013 for which they elected to defer payment until retirement in the form of share-settled units. These expenses are included in general and administrative expense on our consolidated statements of income (loss) and comprehensive income (loss).
Share-Based Compensation
The fair value of awards granted to retirement-eligible employees and expensed at the date of grant was $517,000 in 2015, $760,000 in 2014 and $590,000 in 2013. Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options is $5,109,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years. We did not capitalize any share-based compensation in 2015, 2014 or 2013.
In 2015 and 2014, we issued 288,089 and 215,561 shares out of our treasury stock associated with vesting of stock-based awards or exercise of stock options, net of 51,521 and 55,238 shares withheld having a value of $762,000 and $1,043,000 for payroll taxes in connection with vesting of stock-based awards or exercise of stock options which are reflected in financing activities in our consolidated statements of cash flows.
A summary of awards granted under our 2007 Stock Incentive Plan follows:
Cash-settled awards
Cash-settled awards granted to our employees in the form of restricted stock units or stock appreciation rights generally vest over three to four years from the date of grant and generally provide for accelerated vesting upon death, disability or if there is a change in control. Vesting for some restricted stock unit awards is also conditioned upon achievement of a minimum one percent annualized return on assets over a three-year period. Cash-settled stock appreciation rights have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. Stock appreciation rights were granted with an exercise price equal to the market value of our stock on the date of grant.
Cash-settled awards granted to our directors in the form of restricted stock units are fully vested at the time of grant and payable upon retirement.
The following table summarizes the activity of cash-settled restricted stock unit awards in 2015:
 
Equivalent
Units
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
185

 
$18.49
Granted
60

 
13.26
Vested
(117
)
 
18.26
Forfeited
(11
)
 
18.83
Non-vested at end of period
117

 
16.00

The weighted average grant date fair value of cash-settled restricted stock unit awards was $18.96 per unit for 2014 and $18.70 per unit for 2013. The fair value of cash-settled restricted stock unit awards settled was $2,469,000 in 2015, $2,286,000 in 2014, and $3,780,000 in 2013. The aggregate current value of non-vested awards is $1,286,000 at year-end 2015 based on a year-end stock price of $10.94.
The following table summarizes the activity of cash-settled stock appreciation rights in 2015:
 
Rights
Outstanding
 
Weighted Average
Exercise Price
 
Weighted Average
Remaining Contractual Term
 
Aggregate Intrinsic Value
(Current Value Less Exercise Price)
 
(In thousands)
 
(Per share)
 
(In years)
 
(In thousands)
Balance at beginning of period
458

 
$12.54
 
4
 
$1,732
Granted
90

 
14.08
 
 
 
 
Exercised
(39
)
 
9.29
 
 
 
 
Forfeited
(22
)
 
15.00
 
 
 
 
Balance at end of period
487

 
12.97
 
4
 
404
Exercisable at end of period
414

 
12.77
 
3
 
404

The intrinsic value of cash-settled stock appreciation rights settled was $206,000 in 2015, $1,181,000 in 2014 and $3,458,000 in 2013.
The fair value of accrued cash-settled awards at year-end 2015 and year-end 2014 were $3,757,000 and $9,560,000 and is included in other liabilities in our consolidated balance sheets.
Equity-settled awards
Equity-settled awards granted to our employees include restricted stock units (RSU), which vest after three years from the date of grant, market-leveraged stock units (MSU), which vest after three years from date of grant and performance stock units (PSU), which generally vest after three years from the date of grant if certain performance goals are met. Equity settled awards in the form of restricted stock units granted to our directors are fully vested at time of grant and settled upon retirement. The following table summarizes the activity of equity-settled awards in 2015:
 
Equivalent
Units
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
710

 
$
19.24

Granted
395

 
12.99

Vested
(340
)
 
14.23

Forfeited
(134
)
 
18.18

Non-vested at end of period
631

 
18.25


In 2015, we granted 234,000 MSU awards. These awards will be settled in common stock based upon our stock price performance over three years from the date of grant. The number of shares to be issued could range from a high of 351,000 shares if our stock price increases by 50 percent or more, to 117,000 shares if our stock price decreases by 50 percent, or could be zero if our stock price decreases by more than 50 percent, the minimum threshold performance. We estimate the grant date fair value of MSU awards using a Monte Carlo simulation pricing model and the following assumptions:
 
 
For the Year
 
 
2015
 
2014
 
2013
Expected stock price volatility
 
32.9
%
 
42.2
%
 
42.2
%
Risk-free interest rate
 
1.0
%
 
0.7
%
 
0.4
%
Expected dividend yield
 
—
%
 
—
%
 
—
%
Weighted average grant date fair value of MSU awards (per unit)
 
$
15.11

 
$
20.38

 
$
21.09


The weighted average grant date fair value of equity-settled awards (RSU, MSU, PSU) per unit in 2015, 2014 and 2013 was $12.99, $19.18 and $20.21. The fair value of equity-settled awards settled was $4,451,000, $3,119,000 and $8,000 in 2015, 2014 and 2013.
Unrecognized share-based compensation expense related to non-vested equity-settled awards is $3,258,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years.
Restricted stock awards
Restricted stock awards generally vest over three years, typically if we achieve a minimum one percent annualized return on assets over such three-year period. The following table summarizes the activity of restricted stock awards in 2015:
 
Restricted
Shares
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
17

 
$
17.56

Granted
—

 
—

Vested
(7
)
 
14.59

Forfeited
(6
)
 
19.00

Non-vested at end of period
4

 
20.55


The fair value of our restricted stock awards settled in 2015, 2014 and 2013 was $88,000, $341,000 and $3,002,000.
Unrecognized share-based compensation expense related to non-vested restricted stock awards is $14,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be one year.
Stock options
Stock options have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. In 2015 and 2013, options were granted with an exercise price equal to the market value of our stock on the date of grant. We did not grant any options in 2014. The following table summarizes the activity of stock option awards in 2015:
 
Options
Outstanding
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Term
 
Aggregate
Intrinsic Value
(Current
Value Less
Exercise Price)
 
(In thousands)
 
(Per share)
 
(In years)
 
(In thousands)
Balance at beginning of period
1,861

 
$
20.74

 
6
 
$
643

Granted
413

 
13.86

 
 
 
 
Exercised
—

 
—

 
 
 
 
Forfeited
(103
)
 
18.01

 
 
 
 
Balance at end of period
2,171

 
19.56

 
5
 
156

Exercisable at end of period
1,687

 
20.83

 
4
 
156


We estimate the grant date fair value of stock options that do not have a market condition using the Black-Scholes option pricing model and the following assumptions:
 
 
For the Year
 
 
2015
 
2013
Expected stock price volatility
 
45.6
%
 
66.8
%
Risk-free interest rate
 
1.8
%
 
1.4
%
Expected life of options (years)
 
6

 
6

Expected dividend yield
 
—
%
 
—
%
Weighted average grant date fair value of options (per share)
 
$
6.51

 
$
11.47


We determine the expected life using the simplified method which utilizes the midpoint between the vesting period and the contractual life of the awards. The expected stock price volatility utilizes our historical volatility for a period corresponding to the expected life of the options.
Stock option awards granted in third quarter 2015 in connection with management promotions have a ten-year term, vest ratably over three years and are exercisable only when our stock price exceeds $17.50 per share. We estimated the fair value of these options with market conditions using Monte Carlo simulation pricing model and the following assumptions:
 
 
For the Year
 
 
2015
Expected stock price volatility
 
61.4
%
Risk-free interest rate
 
2.2
%
Expected dividend yield
 
—
%
Weighted average grant date fair value of options (per share)
 
$
7.87


The fair value of vested stock options was $0 in 2015, $21,000 in 2014 and $1,355,000 in 2013. The intrinsic value of options exercised was $0 in 2015, $568,000 in 2014 and $562,000 in 2013. Unrecognized share-based compensation expense related to non-vested stock options is $1,837,000 at year-end 2015. The weighted average period over which this amount will be recognized is estimated to be two years.
Pre-Spin Awards
Certain of our employees participated in Temple-Inland’s share-based compensation plans. In conjunction with our 2007 spin-off, these awards were equitably adjusted into separate awards of the common stock of Temple-Inland and the spin-off entities.
The intrinsic value of pre-spin awards exercised was $24,000 in 2015, $352,000 in 2014 and $1,382,000 in 2013.
Pre-spin stock option awards to our employees to purchase our common stock have a ten-year term, generally become exercisable ratably over four years and provide for accelerated or continued vesting upon retirement, death, disability or if there is a change in control. At year-end 2015, there were 44,000 pre-spin awards outstanding and exercisable on our stock with a weighted average exercise price of $28.89 and weighted average remaining term of one year.
Long-Term Incentive Compensation
In 2015, we granted $587,000 of long-term incentive compensation in the form of deferred cash compensation. Deferred cash will be paid out after the earlier of three years or the employee's retirement eligibility date and the expense is recognized ratably over the vesting period. The accrued liability was $225,000 at year-end 2015 and is included in other liabilities.
v3.3.1.900
Retirement Plans
 12 Months Ended
Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]  
Retirement Plans
Retirement Plans
Our defined contribution retirement plans include a 401(k) plan, which is funded, and a supplemental plan for certain employees, which is unfunded. The expense of our defined contribution retirement plans was $1,255,000 in 2015, $1,651,000 in 2014 and $1,456,000 in 2013. The unfunded liability for our supplemental plan was $802,000 at year-end 2015 and $715,000 at year-end 2014 and is included in other liabilities.
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2015
Extractive Industries [Abstract]  
Supplemental Oil and Gas Disclosures (Unaudited)
Supplemental Oil and Gas Disclosures (Unaudited)
The following unaudited information regarding our oil and gas reserves has been prepared and is presented pursuant to requirements of the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB).
We lease our mineral interests, principally in Texas and Louisiana, to third-party entities for the exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and we retain a royalty interest and may take an additional participation in production, including a working interest in which we pay a share of the costs to drill, complete and operate a well and receive a proportionate share of the production revenues.
We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to assist in preparing estimates of our proved oil and gas reserves, all of which are located in the U.S., and future net cash flows as of year-end 2015, 2014 and 2013.
These estimates were based on the economic and operating conditions existing at year-end 2015, 2014 and 2013. Proved developed reserves are those quantities of petroleum from existing wells and facilities, which by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward for known reservoirs and under defined economic conditions, operating methods and government regulations.
SEC rules require disclosure of proved reserves using the twelve-month average beginning-of-month price (which we refer to as the average price) for the year. These same average prices also are used in calculating the amount of (and changes in) future net cash inflows related to the standardized measure of discounted future net cash flows.
For 2015, 2014 and 2013, the average spot price per barrel of oil based on the West Texas Intermediate Crude price is $50.28, $94.99 and $96.91 and the average price per MMBTU of gas based on the Henry Hub spot market is $2.59, $4.35 and $3.67. All prices were then adjusted for quality, transportation fees and regional price differentials.
The process of estimating proved reserves and future net cash flows is complex involving decisions and assumptions in evaluating the available engineering and geologic data and prices for oil and gas and the cost to produce these reserves and other factors, many of which are beyond our control. As a result, these estimates are imprecise and should be expected to change as future information becomes available. These changes could be significant. In addition, this information should not be construed as being the current fair market value of our proved reserves.

Estimated Quantities of Proved Oil and Gas Reserves
Estimated quantities of proved oil and gas reserves are summarized as follows:
 
Reserves
 
Oil (a)
(Barrels)
 
Gas
(Mcf)
 
(In thousands)
Consolidated entities:
 
 
 
Year-end 2012
3,220

 
11,722

Revisions of previous estimates
182

 
1,243

Extensions and discoveries
3,085

 
2,046

Acquisitions
35

 
531

Production
(698
)
 
(1,912
)
Year-end 2013
5,824

 
13,630

Revisions of previous estimates
608

 
293

Extensions and discoveries
2,191

 
774

Acquisitions
85

 
31

Sales
(105
)
 
(218
)
Production
(931
)
 
(1,861
)
Year-end 2014
7,672

 
12,649

Revisions of previous estimates
(855
)
 
(1,675
)
Extensions and discoveries
224

 
173

Acquisitions
—

 
—

Sales
(704
)
 
(1,223
)
Production
(1,158
)
 
(1,967
)
Year-end 2015
5,179

 
7,957

Our share of ventures accounted for using the equity method:
 
 
 
Year-end 2012
—

 
2,572

Revisions of previous estimates
—

 
7

Production
—

 
(247
)
Year-end 2013
—

 
2,332

Revisions of previous estimates
—

 
(382
)
Production
—

 
(199
)
Year-end 2014
—

 
1,751

Revisions of previous estimates
—

 
(320
)
Production
—

 
(168
)
Year-end 2015
—

 
1,263

Total consolidated and our share of equity method ventures:
 
 
 
Year-end 2013
 
 
 
Proved developed reserves
3,893

 
13,717

Proved undeveloped reserves
1,931

 
2,245

Total Year-end 2013
5,824

 
15,962

Year-end 2014
 
 
 
Proved developed reserves
5,269

 
12,599

Proved undeveloped reserves
2,403

 
1,801

Total Year-end 2014
7,672

 
14,400

Year-end 2015
 
 
 
Proved developed reserves
5,179

 
9,220

Proved undeveloped reserves
—

 
—

Total Year-end 2015
5,179

 
9,220


 _____________________
(a) 
Includes natural gas liquids (NGLs).

We do not have any estimated reserves of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas.
In 2015, oil and gas properties having reserves consisting of approximately 704,000 barrels of oil and 1,223,000 Mcf of gas located primarily in the Texas Panhandle and Bakken/Three Forks formations were sold. Due to the significant decline in oil and gas prices during 2015, net negative revisions of previous estimates were 855,000 barrels of oil and 1,995,000 Mcf of gas. At year-end 2015, we have no barrels of oil equivalent (BOE) of proved undeveloped (PUD) reserves based on our plan to exit non-core oil and gas working interest assets compared with 2,703,000 BOE of PUD reserves at year-end 2014.
In 2014, increases in extensions and discoveries of 2,191,000 barrels were primarily associated with new reserves in the Bakken/Three Forks formations. An estimated 694,000 barrels of these extensions and discoveries were associated with new producing wells while a further 913,000 barrels of proved undeveloped reserves were added during 2014. Approximately 105,000 barrels of oil and 218,000 Mcf of gas reserves located primarily in Oklahoma were sold during the year. We realized a net positive revision of previous estimates of 608,000 barrels which is primarily driven by improved drilling results in the Bakken/Three Forks formation yielding higher average estimated ultimate recoverable quantities of proved reserves per well.
In 2013, increase in gas prices accounted for about 1,243,000 Mcf of upward revisions in gas reserves for our consolidated entities.
In 2015, 2014 and 2013, reserve additions from new wells drilled and completed during the year are shown for both consolidated entities and ventures accounted for using the equity method under extensions and discoveries. There were 36 new well additions in 2015, 106 new well additions in 2014 and 88 new well additions in 2013.
Capitalized Costs Relating to Oil and Gas Producing Activities
Capitalized costs related to our oil and gas producing activities are as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Consolidated entities:
 
 
 
Unproved oil and gas properties
$
19,441

 
$
90,446

Proved oil and gas properties
119,414

 
221,299

Total costs
138,855

 
311,745

Less accumulated depreciation, depletion and amortization
(58,242
)
 
(48,252
)
 
$
80,613

 
$
263,493


We have not capitalized any costs for our share in ventures accounted for using the equity method.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities:
 
 
 
 
 
Acquisition costs
 
 
 
 
 
Proved properties
$
—

 
$
2,001

 
$
—

Unproved properties
4,832

 
25,666

 
35,806

Exploration costs
17,922

 
39,399

 
10,486

Development costs
27,609

 
40,277

 
54,538

 
$
50,363

 
$
107,343

 
$
100,830


We have not incurred any costs for our share in ventures accounted for using the equity method. In 2015, acquisition of leasehold interests, exploration expenses, and development costs have decreased as a result of our increased focus on exiting and selling our leasehold working interests.
Standardized Measure of Discounted Future Net Cash Flows
Estimates of future cash flows from proved oil and gas reserves are shown in the following table. Estimated income taxes are calculated by applying the appropriate tax rates to the estimated future pre-tax net cash flows less depreciation of the tax basis of properties and the statutory depletion allowance.
 
At Year-End
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities:
 
 
 
 
 
Future cash inflows
$
216,588

 
$
665,657

 
$
544,098

Future production and development costs
(93,623
)
 
(271,735
)
 
(231,801
)
Future income tax expenses
(22,218
)
 
(106,002
)
 
(77,361
)
Future net cash flows
100,747

 
287,920

 
234,936

10% annual discount for estimated timing of cash flows
(33,951
)
 
(124,079
)
 
(99,383
)
Standardized measure of discounted future net cash flows
$
66,796

 
$
163,841

 
$
135,553

Our share in ventures accounted for using the equity method:
 
 
 
 
 
Future cash inflows
$
2,283

 
$
6,186

 
$
4,765

Future production and development costs
(245
)
 
(664
)
 
(512
)
Future income tax expenses
(774
)
 
(2,098
)
 
(1,616
)
Future net cash flows
1,264

 
3,424

 
2,637

10% annual discount for estimated timing of cash flows
(562
)
 
(1,649
)
 
(1,337
)
Standardized measure of discounted future net cash flows
$
702

 
$
1,775

 
$
1,300

Total consolidated and our share of equity method ventures
$
67,498

 
$
165,616

 
$
136,853


Future net cash flows were computed using prices used in estimating proved oil and gas reserves, year-end costs, and statutory tax rates (adjusted for tax deductions) that relate to proved oil and gas reserves.

Changes in the standardized measure of discounted future net cash flow follows:
 
For the Year
 
Consolidated
 
Our Share of Equity
Method Ventures
 
Total
 
(In thousands)
Year-end 2012
$
106,543

 
$
1,413

 
$
107,956

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
23,422

 
415

 
23,837

Net change in future development costs
(2,897
)
 
—

 
(2,897
)
Sales of oil and gas, net of production costs
(56,559
)
 
(801
)
 
(57,360
)
Net change due to extensions and discoveries
54,539

 
—

 
54,539

Net change due to acquisition of reserves
1,160

 
—

 
1,160

Net change due to revisions of quantity estimates
8,673

 
6

 
8,679

Previously estimated development costs incurred
4,124

 
—

 
4,124

Accretion of discount
13,540

 
228

 
13,768

Net change in timing and other
(718
)
 
(31
)
 
(749
)
Net change in income taxes
(16,274
)
 
70

 
(16,204
)
Aggregate change for the year
29,010

 
(113
)
 
28,897

Year-end 2013
135,553

 
1,300

 
136,853

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
(1,064
)
 
1,571

 
507

Net change in future development costs
1,308

 
—

 
1,308

Sales of oil and gas, net of production costs
(63,192
)
 
(787
)
 
(63,979
)
Net change due to extensions and discoveries
58,228

 
—

 
58,228

Net change due to acquisition of reserves
2,778

 
—

 
2,778

Net change due to divestitures of reserves
(5,804
)
 
—

 
(5,804
)
Net change due to revisions of quantity estimates
15,303

 
(343
)
 
14,960

Previously estimated development costs incurred
15,497

 
—

 
15,497

Accretion of discount
18,067

 
210

 
18,277

Net change in timing and other
4,198

 
115

 
4,313

Net change in income taxes
(17,031
)
 
(291
)
 
(17,322
)
Aggregate change for the year
28,288

 
475

 
28,763

Year-end 2014
163,841

 
1,775

 
165,616

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
(136,536
)
 
(1,112
)
 
(137,648
)
Net change in future development costs
92

 
—

 
92

Sales of oil and gas, net of production costs
(31,732
)
 
(428
)
 
(32,160
)
Net change due to extensions and discoveries
11,747

 
—

 
11,747

Net change due to acquisition of reserves
—

 
—

 
—

Net change due to divestitures of reserves
(15,855
)
 
 
 
(15,855
)
Net change due to revisions of quantity estimates
(15,164
)
 
(267
)
 
(15,431
)
Previously estimated development costs incurred
15,096

 
—

 
15,096

Accretion of discount
22,600

 
286

 
22,886

Net change in timing and other
4,018

 
(210
)
 
3,808

Net change in income taxes
48,689

 
658

 
49,347

Aggregate change for the year
(97,045
)
 
(1,073
)
 
(98,118
)
Year-end 2015
$
66,796

 
$
702

 
$
67,498


Results of Operations for Oil and Gas Producing Activities
Our royalty interests are contractually defined and based on a percentage of production at prevailing market prices. We receive our percentage of production in cash. Similarly, for operating properties our working interests and the associated net revenue interests are contractually defined and we pay our proportionate share of the capital and operating costs to develop and operate the well and we market our share of the production. Our revenues fluctuate based on changes in the market prices for oil and gas, the decline in production from existing wells, and other factors affecting oil and gas exploration and production activities, including the cost of development and production.
Information about the results of operations of our oil and gas interests follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities
 
 
 
 
 
Revenues
$
51,553

 
$
82,919

 
$
69,036

Production costs
(19,820
)
 
(19,727
)
 
(12,477
)
Exploration costs
(11,864
)
 
(17,416
)
 
(10,486
)
Depreciation, depletion, amortization
(28,774
)
 
(29,442
)
 
(19,552
)
Non-cash impairment of proved oil and gas properties and unproved leasehold interests
(164,831
)
 
(32,665
)
 
(473
)
Oil and gas administrative expenses
(11,700
)
 
(17,000
)
 
(14,407
)
Accretion expense
(144
)
 
(121
)
 
(94
)
Income tax expenses
14,717

 
13,398

 
(3,471
)
Results of operations
(170,863
)
 
(20,054
)
 
8,076

Our share in ventures accounted for using the equity method:
 
 
 
 
 
Revenues
$
428

 
$
786

 
$
801

Production costs
(102
)
 
(105
)
 
(123
)
Oil and gas administrative expenses
(51
)
 
(95
)
 
(86
)
Income tax expenses
21

 
(235
)
 
(178
)
Results of operations
$
296

 
$
351

 
$
414

Total results of operations
$
(170,567
)
 
$
(19,703
)
 
$
8,490


Production costs represent our share of oil and gas production severance taxes, and lease operating expenses. Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs.
v3.3.1.900
Summary of Quarterly Results of Operations (Unaudited)
 12 Months Ended
Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]  
Summary of Quarterly Results of Operations (Unaudited)
Summary of Quarterly Results of Operations (Unaudited)
Summarized quarterly financial results for 2015 and 2014 follows:
 
First Quarter (a)
 
Second Quarter (a)
 
Third
    Quarter (a)
 
Fourth
    Quarter (a)
 
(In thousands, except per share amounts)
2015
 
 
 
 
 
 
 
Total revenues
$
47,805

 
$
57,430

 
$
43,168

 
$
114,018

Gross profit (loss)
17,289

 
(35,009
)
 
(69,572
)
 
8,341

Operating income (loss)
(7,737
)
 
(52,714
)
 
(94,751
)
 
(9,482
)
Equity in earnings of unconsolidated ventures
3,045

 
5,584

 
2,909

 
4,470

Income (loss) before taxes
(12,596
)
 
(55,062
)
 
(100,095
)
 
(11,983
)
Net income (loss) attributable to Forestar Group Inc.
(8,158
)
 
(34,507
)
 
(164,216
)
 
(6,166
)
 
 
 
 
 
 
 
 
Net income (loss) per share — basic
$
(0.24
)
 
$
(1.01
)
 
$
(4.79
)
 
$
(0.18
)
Net income (loss) per share — diluted
$
(0.24
)
 
$
(1.01
)
 
$
(4.79
)
 
$
(0.18
)
 
 
 
 
 
 
 
 
2014
 
 
 
 
 
 
 
Total revenues
$
84,605

 
$
83,013

 
$
58,840

 
$
80,316

Gross profit (loss)
35,025

 
33,261

 
19,606

 
(6,259
)
Operating income (loss)
15,883

 
26,942

 
12,716

 
(16,783
)
Equity in earnings of unconsolidated ventures
991

 
958

 
2,016

 
4,720

Income (loss) before taxes
13,665

 
22,799

 
7,994

 
(18,713
)
Net income (loss) attributable to Forestar Group Inc.
8,334

 
14,822

 
5,227

 
(11,800
)
 
 
 
 
 
 
 
 
Net income (loss) per share — basic
$
0.20

 
$
0.34

 
$
0.12

 
$
(0.34
)
Net income (loss) per share — diluted
$
0.19

 
$
0.34

 
$
0.12

 
$
(0.34
)
 _____________________
(a)Non-cash impairment charges for unproved leasehold interests and proved oil and gas properties included in our quarterly financial results are as follows:
 
First Quarter
 
Second Quarter
 
Third
Quarter
 
Fourth
Quarter
 
(In thousands)
2015
$
7

 
$
45,938

 
$
81,240

 
$
37,646

2014
755

 
584

 
735

 
30,591
v3.3.1.900
Consolidated Real Estate and Accumulated Depreciation
 12 Months Ended
Dec. 31, 2015
SEC Schedule III, Real Estate and Accumulated Depreciation Disclosure [Abstract]  
Consolidated Real Estate and Accumulated Depreciation
Forestar Group Inc.
Schedule III — Consolidated Real Estate and Accumulated Depreciation
Year-End 2015
(In thousands)
 
 
 
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 
Gross Amount Carried at End of Period
 
 
 
 
Description
Encumbrances
 
Land
 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 
Total
 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Entitled, Developed, and Under Development Projects:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ARIZONA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pima County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dove Mountain
 
 
$
5,860

 
 
 
$
3

 
 
 
$
5,863

 
 
 
$
5,863

 
 
 
 
 
2015
CALIFORNIA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contra Costa County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
San Joaquin River
 
 
12,225

 
 
 
(3,310
)
 
 
 
8,915

 
 
 
8,915

 
 
 
 
 
(b) 
COLORADO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Douglas County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinery West
 
 
7,308

 
 
 
3,691

 
 
 
10,999

 
 
 
10,999

 
 
 
2006
 
2006
Weld County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Buffalo Highlands
 
 
3,001

 
 
 
547

 
 
 
3,548

 
 
 
3,548

 
 
 
2006
 
2005
Johnstown Farms
 
 
2,749

 
 
 
4,024

 
$
188

 
6,961

 
 
 
6,961

 
 
 
2002
 
2002
Stonebraker
 
 
3,878

 
 
 
(1,469
)
 
 
 
2,409

 
 
 
2,409

 
 
 
2005
 
2005
GEORGIA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cobb County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
West Oaks
 
 
1,669

 
 
 
232

 
 
 
1,901

 
 
 
1,901

 
 
 
2015
 
2015
Paulding County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Harris Place
 
 
265

 
 
 
(111
)
 
 
 
154

 
 
 
154

 
 
 
 
 
2012
Seven Hills
 
 
2,964

 
 
 
145

 
 
 
3,109

 
 
 
3,109

 
 
 
 
 
2012
MISSOURI
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Clay County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Somerbrook
 
 
3,061

 
 
 
(218
)
 
13

 
2,856

 
 
 
2,856

 
 
 
2003
 
2001
NORTH CAROLINA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mecklenburg County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Walden
 
 
12,085

 
 
 
345

 
 
 
12,430

 
 
 
12,430

 
 
 
 
 
2015
SOUTH CAROLINA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lancaster County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ansley Park
 
 
5,089

 
 
 
574

 
 
 
5,663

 
 
 
5,663

 
 
 
 
 
2015
York County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Habersham
 
 
3,877

 
 
 
3,072

 
239

 
7,188

 
 
 
7,188

 
 
 
2014
 
2013
 
 
 
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 
Gross Amount Carried at End of Period
 
 
 
 
Description
Encumbrances
 
Land
 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 
Total
 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
TENNESEE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Williamson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Morgan Farms
 
 
$
6,841

 
 
 
$
(552
)
 
$
166

 
$
6,455

 
 
 
$
6,455

 
 
 
2013
 
2013
Vickery Park
 
 
3,575

 
 
 
560

 
 
 
4,135

 
 
 
4,135

 
 
 
 
 
2015
Weatherford Estates
 
 
856

 
 
 
1,603

 
 
 
2,459

 
 
 
2,459

 
 
 
2015
 
2014
Wilson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beckwith Crossing
 
 
1,294

 
 
 
2,519

 
 
 
3,813

 
 
 
3,813

 
 
 
2015
 
2014
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bastrop County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Hunter’s Crossing
 
 
3,613

 
 
 
5,180

 
358

 
9,151

 
 
 
9,151

 
 
 
2001
 
2001
The Colony
 
 
8,726

 
 
 
15,206

 
161

 
24,093

 
 
 
24,093

 
 
 
1999
 
1999
Bexar County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cibolo Canyons
 
 
17,305

 
 
 
40,243

 
1,202

 
58,750

 
 
 
58,750

 
 
 
2004
 
1986
Calhoun County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Caracol
$
2,237

 
8,603

 
 
 
3,688

 
2,047

 
14,338

 
 
 
14,338

 
 
 
2006
 
2006
Collin County
Lakes of Prosper
 
 
8,951

 
 
 
(3,550
)
 
180

 
5,581

 
 
 
5,581

 
 
 
 
 
2012
Maxwell Creek
 
 
9,904

 
 
 
(7,946
)
 
635

 
2,593

 
 
 
2,593

 
 
 
2000
 
2000
Parkside
 
 
2,177

 
 
 
3,661

 
 
 
5,838

 
 
 
5,838

 
 
 
2014
 
2013
Timber Creek
 
 
7,282

 
 
 
9,137

 
 
 
16,419

 
 
 
16,419

 
 
 
2007
 
2007
Village Park
 
 
4,772

 
 
 
(4,765
)
 
45

 
52

 
 
 
52

 
 
 
 
 
2012
Comal County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oak Creek Estates
 
 
1,921

 
 
 
2,314

 
175

 
4,410

 
 
 
4,410

 
 
 
2006
 
2005
Dallas County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stoney Creek
 
 
12,822

 
 
 
2,783

 
49

 
15,654

 
 
 
15,654

 
 
 
2007
 
2007
Denton County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lantana


 
27,673

 
 
 
(7,382
)
 
 
 
20,291

 
 
 
20,291

 
 
 
2000
 
1999
River's Edge
 
 
1,227

 
 
 
381

 
 
 
1,608

 
 
 
1,608

 
 
 
 
 
2014
The Preserve at Pecan Creek
 
 
5,855

 
 
 
(3,905
)
 
436

 
2,386

 
 
 
2,386

 
 
 
2006
 
2005
Fort Bend County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summer Lakes

 
4,269

 
 
 
968

 
 
 
5,237

 
 
 
5,237

 
 
 
2013
 
2012
Summer Park

 
4,804

 
 
 
57

 
 
 
4,861

 
 
 
4,861

 
 
 
2013
 
2012
Willow Creek Farms
459

 
3,479

 
 
 
(311
)
 
90

 
3,258

 
 
 
3,258

 
 
 
2012
 
2012
Harris County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Barrington
 
 
8,950

 
 
 
(7,062
)
 
 
 
1,888

 
 
 
1,888

 
 
 
 
 
2011
City Park
1,659

 
3,946

 
 
 
1,463

 
1,641

 
7,050

 
 
 
7,050

 
 
 
2002
 
2001
Imperial Forest
 
 
5,345

 
 
 
819

 
 
 
6,164

 
 
 
6,164

 
 
 
2015
 
2014
 
 
 
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 
Gross Amount Carried at End of Period
 
 
 
 
Description
Encumbrances
 
Land
 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 
Total
 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Hays County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Arrowhead Ranch
 
 
$
12,856

 
 
 
$
6,537

 
 
 
$
19,393

 
 
 
$
19,393

 
 
 
2015
 
2007
Nueces County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Tortuga Dunes
 
 
12,080

 
 
 
9,670

 
 
 
21,750

 
 
 
21,750

 
 
 
 
 
2006
Tarrant County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summer Creek Ranch
 
 
2,887

 
 
 
(1,601
)
 
 
 
1,286

 
 
 
1,286

 
 
 
 
 
2012
The Bar C Ranch
 
 
1,365

 
 
 
3,258

 
$
32

 
4,655

 
 
 
4,655

 
 
 
 
 
2012
Williamson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
La Conterra
 
 
4,024

 
 
 
(2,790
)
 
293

 
1,527

 
 
 
1,527

 
 
 
 
 
2006
Westside at Buttercup Creek
 
 
13,149

 
 
 
(13,586
)
 
488

 
51

 
 
 
51

 
 
 
1993
 
1993
Other
 
 
8,443

 
 
 
(4,097
)
 
653

 
4,999

 
 
 
4,999

 
 
 
 
 
 
Total Entitled, Developed, and Under Development Projects
$
4,355

 
$
283,025

 
$
—

 
$
60,025

 
$
9,091

 
$
352,141

 
$
—

 
$
352,141

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land and Land in Entitlement:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CALIFORNIA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Los Angeles County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Land In Entitlement Process
 
 
$
3,950

 
 
 
$
19,564

 
 
 
$
23,514

 
 
 
$
23,514

 
 
 
 
 
1997
GEORGIA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bartow County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
4,057

 
 
 
(2,440
)
 
 
 
1,617

 
 
 
1,617

 
 
 
 
 
(b) 
Carroll County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
13,564

 
 
 
2,580

 
 
 
16,144

 
 
 
16,144

 
 
 
 
 
(b) 
Cherokee County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
6,043

 
 
 
536

 
 
 
6,579

 
 
 
6,579

 
 
 
 
 
(b) 
Coweta County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
3,089

 
 
 
1,343

 
 
 
4,432

 
 
 
4,432

 
 
 
 
 
(b) 
Dawson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
2,228

 
 
 
3,381

 
 
 
5,609

 
 
 
5,609

 
 
 
 
 
(b) 
Gilmer County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
2,748

 
 
 
(62
)
 
 
 
2,686

 
 
 
2,686

 
 
 
 
 
(b) 
Haralson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
195

 
 
 
88

 
 
 
283

 
 
 
283

 
 
 
 
 
(b) 
Lumpkin County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
3,015

 
 
 
(93
)
 
 
 
2,922

 
 
 
2,922

 
 
 
 
 
(b) 
Paulding County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
7,494

 
 
 


 
 
 
7,494

 
 
 
7,494

 
 
 
 
 
(b) 
 
 
 
Initial Cost to
Company
 
Costs Capitalized
Subsequent to Acquisition
 
Gross Amount Carried at End of Period
 
 
 
 
Description
Encumbrances
 
Land
 
Buildings &
Improvements
 
Improvements
less Cost of
Sales and
Other
 
Carrying
Costs(a)
 
Land & Land
Improvements
 
Buildings &
Improvements
 
Total
 
Accumulated
Depreciation
 
Date of
Construction
 
Date
Acquired
Pickens County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
$
3,150

 
 
 
$
(108
)
 
 
 
$
3,042

 
 
 
$
3,042

 
 
 
 
 
(b) 
Polk County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
2,354

 
 
 
(198
)
 
 
 
2,156

 
 
 
2,156

 
 
 
 
 
(b) 
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bexar County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
 
 
 
 
3,036

 
 
 
3,036

 
 
 
3,036

 
 
 
 
 
(b) 
Harris County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Land in Entitlement Process
 
 
685

 
 
 
1,151

 
 
 
1,836

 
 
 
1,836

 
 
 
 
 
(b) 
Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undeveloped Land
 
 
9,170

 
 
 
7,661

 
 
 
16,831

 
 
 
16,831

 
 
 
 
 
(b) 
Total Undeveloped Land and Land in Entitlement
$
—

 
$
61,742

 
$
—

 
$
36,439

 
$
—

 
$
98,181

 
$
—

 
$
98,181

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Producing Properties:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NORTH CAROLINA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mecklenburg County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dillon
 
 
$
5,779

 
 
 
$
14,208

 
 
 
$
19,987

 
 
 
$
19,987

 
 
 
 
 
2012
TENNESSEE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Davidson County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Music Row
 
 
6,607

 
 
 
3,340

 
 
 
9,947

 
 
 
9,947

 
 
 
 
 
2014
TEXAS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Travis County
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Eleven
$
23,936

 
7,940

 
$
45,956

 
—

 
 
 
7,940

 
$
45,956

 
53,896

 
$
(2,861
)
 
2013
 
2014
Downtown Edge
 
 
11,202

 
 
 
1,504

 
 
 
12,706

 
 
 
12,706

 
 
 
 
 
2014
Radisson Hotel & Suites
15,400

 
 
 
10,603

 
52,286

 
 
 
—

 
62,889

 
62,889

 
(29,268
)
 
 
 
(b) 
West Austin
 
 
7,275

 
 
 
1,822

 
 
 
9,097

 
 
 
9,097

 
 
 
 
 
2014
Total Income Producing Properties
$
39,336

 
$
38,803

 
$
56,559

 
$
73,160

 
$
—

 
$
59,677

 
$
108,845

 
$
168,522

 
$
(32,129
)
 
 
 
 
Total
$
43,691

 
$
383,570

 
$
56,559

 
$
169,624

 
$
9,091

 
$
509,999

 
$
108,845

 
$
618,844

 
$
(32,129
)
 
 
 
 
  _____________________
(a) 
We do not capitalize carrying costs until development begins.
(b) 
The acquisition date is not available.
Reconciliation of real estate:
 
 
2015
 
2014
 
2013
 
 
(In thousands)
Balance at beginning of year
 
$
607,133

 
$
547,530

 
$
545,370

Amounts capitalized
 
124,633

 
214,184

 
111,428

Amounts retired or adjusted
 
(112,922
)
 
(154,581
)
 
(109,268
)
Balance at close of period
 
$
618,844

 
$
607,133

 
$
547,530

Reconciliation of accumulated depreciation:
 
 
2015
 
2014
 
2013
 
 
(In thousands)
Balance at beginning of year
 
$
(31,377
)
 
$
(28,066
)
 
$
(28,220
)
Depreciation expense
 
(6,810
)
 
(3,319
)
 
(2,185
)
Amounts retired or adjusted
 
6,058

 
8

 
2,339

Balance at close of period
 
$
(32,129
)
 
$
(31,377
)
 
$
(28,066
)
v3.3.1.900
(Notes)
 12 Months Ended
Dec. 31, 2015
Subsequent Events [Abstract]  
Subsequent Events
Subsequent Events
On January 28, 2016, we announced that our multifamily business is non-core. As a result, we plan to opportunistically exit our multifamily portfolio and no longer allocate capital to new communities in this business.
On February 4, 2016, we entered into a Purchase and Sale Agreement to sell the Radisson Hotel & Suites in Austin for $130,000,000. This transaction is subject to normal closing conditions and is expected to close in second quarter 2016.
On March 1, 2016, we sold our remaining Kansas and Nebraska oil and gas properties for $21,000,000, with a $2,000,000 contingency payment if the WTI oil price exceeds $60 Bbl for 60 consecutive trading days within one year following closing. We will incur an additional loss related to the sale of Kansas and Nebraska oil and gas properties due to allocation of goodwill on a relative fair value basis to the disposal group that constitutes a business.
v3.3.1.900
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2015
Accounting Policies [Abstract]  
Basis of Presentation
Basis of Presentation
Our consolidated financial statements include the accounts of Forestar Group Inc., all subsidiaries, ventures and other entities in which we have a controlling interest. We account for our investment in other entities in which we have significant influence over operations and financial policies using the equity method (we recognize our share of the entities’ income or loss and any preferential returns and treat distributions as a reduction of our investment). We eliminate all material intercompany accounts and transactions. Noncontrolling interests in consolidated pass-through entities are recognized before income taxes.
We prepare our financial statements in accordance with generally accepted accounting principles in the United States, which require us to make estimates and assumptions about future events. Actual results can, and probably will, differ from those we currently estimate. Examples of significant estimates include those related to allocating costs to real estate, measuring long-lived assets for impairment, oil and gas revenue accruals, capital expenditure and lease operating expense accruals associated with our oil and gas production activities, oil and gas reserves and depletion of our oil and gas properties.
Cash and Cash Equivalents
Cash and Cash Equivalents
Cash and cash equivalents include cash and other short-term instruments with original maturities of three months or less. At year-end 2015 and 2014, restricted cash was $200,000 and $217,000 and is included in other assets.
Cash Flows
Cash Flows
Expenditures for the acquisition and development of single-family and multifamily real estate that we intend to develop for sale are classified as operating activities. Expenditures for the acquisition and development of properties to be held and operated, investment in oil and gas properties and equipment, and business acquisitions are classified as investing activities. Our accrued capital expenditures for unproved leasehold acquisitions and drilling and completion costs at year-end 2015 and 2014 were $7,033,000 and $19,405,000 and are included in other accrued expenses in our consolidated balance sheets. These oil and gas property additions will be reflected as cash used for investing activities in the period the accrued payables are settled.
Capitalized Software
Capitalized Software
We capitalize purchased software costs as well as the direct internal and external costs associated with software we develop for our own use. We amortize these capitalized costs using the straight-line method over estimated useful lives generally ranging from three to five years. The carrying value of capitalized software was $237,000 at year-end 2015 and $1,188,000 at year-end 2014 and is included in other assets. The amortization of these capitalized costs was $996,000 in 2015, $1,067,000 in 2014 and $1,593,000 in 2013 and is included in general and administrative and operating expenses.
Environmental and Asset Retirement Obligations
Environmental and Asset Retirement Obligations
We recognize environmental remediation liabilities on an undiscounted basis when environmental assessments or remediation are probable and we can reasonably estimate the cost. We adjust these liabilities as further information is obtained or circumstances change. Our asset retirement obligations are related to the abandonment and site restoration requirements that result from the acquisition, construction and development of our oil and gas properties. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Accretion expense related to the asset retirement obligation and depletion expense related to capitalized asset retirement cost is included in cost of oil and gas producing activities on our consolidated statements of income (loss).
The following summarizes the changes in asset retirement obligations:
 
Year-End
 
2015
 
2014
 
(In thousands)
Beginning balance
$
1,807

 
$
1,483

Additions
65

 
314

Property dispositions
(119
)
 
(230
)
Change in estimate
—

 
118

Liabilities settled
(139
)
 
—

Accretion expense
144

 
122

 
$
1,758

 
$
1,807
Fair Value Measurements
Fair Value Measurements
Financial instruments for which we did not elect the fair value option include cash and cash equivalents, accounts and notes receivables, other assets, long-term debt, accounts payable and other liabilities. With the exception of long-term notes receivable and debt, the carrying amounts of these financial instruments approximate their fair values due to their short-term nature or variable interest rates.
Goodwill and Other Intangible Assets
Goodwill and Other Intangible Assets
We record goodwill when the purchase price of a business acquisition exceeds the estimated fair value of net identified tangible and intangible assets acquired. We do not amortize goodwill or other indefinite lived intangible assets. Instead, we measure these assets for impairment based on the estimated fair values at least annually or more frequently if impairment indicators exist. We perform the annual impairment measurement in the fourth quarter of each year. Intangible assets with finite useful lives are amortized over their estimated useful lives.
In 2015, we performed our annual goodwill impairment evaluation and concluded that goodwill was not impaired as the estimated fair value exceeded the carrying value.
Income Taxes
Income Taxes
We provide deferred income taxes using current tax rates for temporary differences between the financial accounting carrying value of assets and liabilities and their tax accounting carrying values. We recognize and value income tax exposures for the various taxing jurisdictions where we operate based on laws, elections, commonly accepted tax positions, and management estimates. We include tax penalties and interest in income tax expense. We provide a valuation allowance for any deferred tax asset that is not likely to be recoverable in future periods.
When we believe a tax position is supportable but the outcome uncertain, we include the item in our tax return but do not recognize the related benefit in our provision for taxes. Instead, we record a reserve for unrecognized tax benefits, which represents our expectation of the most likely outcome considering the technical merits and specific facts of the position. Changes to liabilities are only made when an event occurs that changes the most likely outcome, such as settlement with the relevant tax authority, expiration of statutes of limitations, changes in tax law, or recent court rulings.
Owned Mineral Interests
Owned Mineral Interests
When we lease our mineral interests to third-party exploration and production entities, we retain a royalty interest and may take an additional participation in production, including a working interest. Mineral interests and working interests related to our owned mineral interests are included in oil and gas properties and equipment on our balance sheet, net of accumulated depletion.
Oil and Gas Properties
Oil and Gas Properties
We use the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests leased, costs to drill and complete development of oil and gas wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves and if determined incapable of producing commercial quantities of oil and gas these costs are expensed as dry hole costs. At year-end 2014, we had $8,575,000 in capitalized exploratory well costs pending determination of proved reserves, of which $8,454,000 was charged to expense in 2015 with the remaining capitalized based on determination of proved reserves. At year-end 2015, we have no capitalized exploratory well costs pending determination of proved reserves. Exploration costs include dry hole costs, geological and geophysical costs, expired unproved leasehold costs and seismic studies, and are expensed as incurred. Production costs incurred to maintain wells and related equipment are charged to expense as incurred.
Depreciation and depletion of producing oil and gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible drilling and completion costs. Proved reserves are used to compute unit rates for unamortized acquisition of proved leasehold costs. Unit-of-production amortization rates are revised whenever there is an indication of the need for revision but at least once a year and those revisions are accounted for prospectively as changes in accounting estimates.
Impairment of Oil and Gas Properties
We evaluate our oil and gas properties, including facilities and equipment, for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.
The assessment of unproved leasehold properties to determine any possible impairment requires significant judgment. We assess our unproved leasehold properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Impairment expense for proved and unproved oil and gas properties are included in costs of oil and gas producing activities.
Operating Leases
Operating Leases
We occupy office space in various locations under operating leases. The lease agreements may contain rent escalation clauses, construction allowances and/or contingent rent provisions. We expense operating leases ratably over the shorter of the useful life or the lease term. For scheduled rent escalation clauses, we recognize the base rent expense on a straight-line basis and record the difference between the recognized rent expense and the amounts payable under the lease as deferred lease credits included in other liabilities in the consolidated balance sheets. Deferred lease credits are amortized over the lease term. For construction allowances, we record leasehold improvement assets included in property and equipment in the consolidated balance sheets amortized over the shorter of their economic lives or the lease term. The related deferred lease credits are amortized as a reduction of rent expense over the lease term.
Property and Equipment
Property and Equipment
We carry property and equipment at cost less accumulated depreciation. We capitalize the cost of significant additions and improvements, and we expense the cost of repairs and maintenance. We capitalize interest costs incurred on major construction projects. We depreciate these assets using the straight-line method over their estimated useful lives as follows:
 
Estimated
 
Year-End
 
Useful Lives
 
2015
 
2014
 
 
 
(In thousands)
Buildings and building improvements
10 to 40 years
 
$
4,044

 
$
4,461

Property and equipment
2 to 10 years
 
12,230

 
14,084

 
 
 
16,274

 
18,545

Less: accumulated depreciation
 
 
(5,542
)
 
(6,918
)
 
 
 
$
10,732

 
$
11,627


Depreciation expense of property and equipment was $1,067,000 in 2015, $903,000 in 2014 and $1,028,000 in 2013.
Real Estate
Real Estate
We carry real estate at the lower of cost or fair value less cost to sell. We capitalize interest costs once development begins, and we continue to capitalize throughout the development period. We also capitalize infrastructure, improvements, amenities, and other development costs incurred during the development period. We determine the cost of real estate sold using the relative sales value method. When we sell real estate from projects that are not finished, we include in the cost of real estate sold estimates of future development costs through completion, allocated based on relative sales values. These estimates of future development costs are reevaluated at least annually, with any adjustments being allocated prospectively to the remaining units available for sale. We receive cash deposits from home builders for purchases of vacant developed lots from community development projects. These earnest money deposits are released to the home builders as lots are developed and sold.
Income producing properties are carried at cost less accumulated depreciation computed using the straight-line method over their estimated useful lives.
We have agreements with utility or improvement districts, principally in Texas, whereby we agree to convey to the district's water, sewer and other infrastructure-related assets we have constructed in connection with projects within their jurisdiction. The reimbursement for these assets ranges from 70 to 90 percent of allowable cost as defined by the district. The transfer is consummated and we receive payment when the districts have a sufficient tax base to support funding of their bonds. The cost we incur in constructing these assets is included in capitalized development costs, and upon collection, we remove the assets from capitalized development costs. We provide an allowance to reflect our past experiences related to claimed allowable development costs.
Impairment of Real Estate Long-Lived Assets
We review real estate long-lived assets held for use for impairment when events or circumstances indicate that their carrying value may not be recoverable. Impairment exists if the carrying amount of the long-lived asset is not recoverable from the undiscounted cash flows expected from its use and eventual disposition. We determine the amount of the impairment loss by comparing the carrying value of the long-lived asset to its estimated fair value. In the absence of quoted market prices, we determine estimated fair value generally based on the present value of future probability weighted cash flows expected from the sale of the long-lived asset. Non-cash impairment charges related to our owned and consolidated real estate assets are included in cost of real estate sales and other.
Revenue
Revenue
Real Estate
We recognize revenue from sales of real estate when a sale is consummated, the buyer’s initial investment is adequate, any receivables are probable of collection, the usual risks and rewards of ownership have been transferred to the buyer, and we do not have significant continuing involvement with the real estate sold. If we determine that the earnings process is not complete, we defer recognition of any gain until earned. We recognize revenue from hotel room sales and other guest services when rooms are occupied and other guest services have been rendered. We recognize rental revenues from our multifamily properties when earned in accordance with the terms of the respective leases on a straight-line basis for the period of occupancy.
We recognize construction revenues on multifamily projects that we develop as a general contractor. Construction revenues are recognized as costs are incurred plus fixed fee earned. We are reimbursed for costs paid to subcontractors plus we may earn a development and construction management fee on multifamily projects we develop, both of which are included in commercial and income producing properties revenue. On multifamily projects where our fee is based on a fixed fee plus guaranteed maximum price contract, any cost overruns incurred during construction, as compared to the original budget, will reduce the net fee generated on these projects. Any excess cost overruns estimated over the net fee generated are recognized in the period in which they become evident. At year-end 2015, we are not a general contractor on any of the multifamily projects currently under construction and we do not anticipate to be a general contractor on any new multifamily projects.
We exclude from revenue amounts we collect from utility or improvement districts related to the conveyance of water, sewer and other infrastructure related assets. We also exclude from revenue amounts we collect for timber sold on land being developed. These proceeds reduce capitalized development costs. We exclude from revenue amounts we collect from customers that represent sales tax or other taxes that are based on the sale. These amounts are included in other accrued expenses until paid.
Oil and Gas
We recognize revenue as oil and gas is produced and sold. There are a significant amount of oil and gas properties which we do not operate and, therefore, revenue is typically recorded in the month of production based on an estimate of our share of volumes produced and prices realized. We obtain the most current available production data from the operators and price indices for each well to estimate the accrual of revenue. Obtaining production data on a timely basis for some wells is not feasible; therefore we utilize past production receipts and estimated sales price information to estimate accrual of working interest revenue on all other non-operated wells each month. Revisions to such estimates are recorded as actual results become known. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible.
A majority of our sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined upon a percentage of pre-determined and published monthly index price. The terms of these contracts have not had an effect on how we recognize revenue.
We recognize revenue from mineral bonus payments received as a result of leasing our owned mineral interests to others when we have received an executed agreement with the exploration company transferring the rights to any oil or gas it may find and requiring drilling be done within a specified period, the payment has been collected, and we have no obligation to refund the payment. We recognize revenue from delay rentals received if drilling has not started within the specified period and when the payment has been collected. We recognize revenue from mineral royalties when the minerals have been delivered to the buyer, the value is determinable, and we are reasonably sure of collection.
Other Natural Resources
We recognize revenue from timber sales upon passage of title, which occurs at delivery; when the price is fixed and determinable; and we are reasonably sure of collection. We recognize revenue from recreational leases on the straight-line basis over the lease term.
Share-Based Compensation
Share-Based Compensation
We use the Black-Scholes option pricing model for stock options, Monte Carlo simulation pricing model for market-leveraged stock units and for stock options with market conditions, grant date fair value for equity-settled awards and period-end fair value for cash-settled awards. We expense share-based awards ratably over the vesting period or earlier based on retirement eligibility.
Timber
Timber
We carry timber at cost less the cost of timber cut. We expense the cost of timber cut based on the relationship of the timber carrying value to the estimated volume of recoverable timber multiplied by the amount of timber cut. We include the cost of timber cut in cost of other natural resources in the income statement. We determine the estimated volume of recoverable timber using statistical information and other data related to growth rates and yields gathered from physical observations, models and other information gathering techniques. Changes in yields are generally due to adjustments in growth rates and similar matters and are accounted for prospectively as changes in estimates. We capitalize reforestation costs incurred in developing viable seedling plantations (up to two years from planting), such as site preparation, seedlings, planting, fertilization, insect and wildlife control, and herbicide application. We expense all other costs, such as property taxes and costs of forest management personnel, as incurred. Once the seedling plantation is viable, we expense all costs to maintain the viable plantations, such as fertilization, herbicide application, insect and wildlife control, and thinning, as incurred.
We own directly or through ventures about 89,000 acres of non-core timberland and undeveloped land, primarily in Georgia. The non-cash cost of timber cut and sold is $250,000 in 2015, $371,000 in 2014 and $609,000 in 2013 and is included in depreciation, depletion and amortization in our statement of cash flows.
New and Pending Accounting Pronouncements
Pending Accounting Pronouncements
Pending Accounting Standards
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for annual and interim periods beginning after December 15, 2016. In July 2015, the FASB decided to defer the effective date of the new standard by one year. This deferral results in the updated standard being effective after December 15, 2017. We have not yet selected a transition method and we are currently evaluating the effect that the updated standard will have on our earnings, financial position and disclosures.
In January 2015, the FASB issued ASU 2015-01, Income Statement - Extraordinary and Unusual Items (Subtopic 225-20), which eliminates the concept of extraordinary items from U.S. GAAP. The updated standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.
In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis (Topic 810), requiring entities to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. The revised consolidation model: (1) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, (3) affects the consolidation analysis of reporting entities that are involved with VIEs, and (4) provides a scope exception from consolidation guidance for reporting entities with interests in certain legal entities. The updated standard is effective for financial statements issued for annual and interim periods beginning after December 15, 2015. Early adoption is permitted. The updated standard may be applied retrospectively or using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. The adoption of this guidance is not expected to have an impact on our financial statements and related disclosures.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as part of its initiative to reduce complexity in accounting standards. To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update), which allows an entity to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The updated standards are effective for financial statements issued for annual and interim periods beginning after December 15, 2015. The updated standards are not expected to materially impact our financial position or disclosures.
In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40), in order to provide clarification on whether a cloud computing arrangement includes a software license. If a software license is included, the customer should account for the license consistent with its accounting of other software licenses. If a software license is not included, the arrangement should be accounted for as a service contract. The update is effective for reporting periods beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.
In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Updates. The amendments in this update cover a wide range of topics in the codification and are generally categorized as follows: Amendments Related to Differences between Original Guidance and the Codification; Guidance Clarification and Reference Corrections; Simplification; and, Minor Improvements. The amendments are effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The adoption of this standard is not expected to impact our financial position or results of operations.
In November 2015, the FASB issued ASU 2015-17, Income Taxes - Balance Sheet Classification of Deferred Taxes (Subtopic 740). The ASU requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The amendments in this update are effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2016. We do not currently present a classified consolidated balance sheet and therefore this pronouncement will have no impact on our financial statements and related disclosures.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessees to put most leases on their balance sheets but recognize expenses on their income statements in a manner that is similar to today's accounting. This guidance also eliminates today's real estate-specific provisions for all entities. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. This guidance is effective in 2019, and interim periods within that year. Early adoption is permitted. The new leases standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. We are currently evaluating the effect the updated standard will have on our financial position and disclosures.
v3.3.1.900
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2015
Accounting Policies [Abstract]  
Schedule of Change in Asset Retirement Obligation
The following summarizes the changes in asset retirement obligations:
 
Year-End
 
2015
 
2014
 
(In thousands)
Beginning balance
$
1,807

 
$
1,483

Additions
65

 
314

Property dispositions
(119
)
 
(230
)
Change in estimate
—

 
118

Liabilities settled
(139
)
 
—

Accretion expense
144

 
122

 
$
1,758

 
$
1,807
Schedule of Property, Plant and Equipment
We depreciate these assets using the straight-line method over their estimated useful lives as follows:
 
Estimated
 
Year-End
 
Useful Lives
 
2015
 
2014
 
 
 
(In thousands)
Buildings and building improvements
10 to 40 years
 
$
4,044

 
$
4,461

Property and equipment
2 to 10 years
 
12,230

 
14,084

 
 
 
16,274

 
18,545

Less: accumulated depreciation
 
 
(5,542
)
 
(6,918
)
 
 
 
$
10,732

 
$
11,627
v3.3.1.900
Goodwill and Other Intangible Assets (Tables)
 12 Months Ended
Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]  
Carrying Value of Goodwill and Other Intangible Assets
Carrying value of goodwill and other intangible assets follows:
 
Year-End
 
2015
 
2014
 
(In thousands)
Goodwill
$
61,164

 
$
63,423

Identified intangibles, net
1,964

 
2,708

 
$
63,128

 
$
66,131
v3.3.1.900
Real Estate (Tables)
 12 Months Ended
Dec. 31, 2015
Real Estate [Abstract]  
Real Estate
Real estate consists of:
 
Year-End 2015
 
Year-End 2014
 
Carrying Value
 
Accumulated Depreciation
 
Net Carrying Value
 
Carrying Value
 
Accumulated Depreciation
 
Net Carrying Value
 
(In thousands)
Entitled, developed and under development projects
$
352,141

 
$
—

 
$
352,141

 
$
321,273

 
$
—

 
$
321,273

Undeveloped land (includes land in entitlement)
98,181

 
—

 
98,181

 
93,182

 
—

 
93,182

Commercial
 
 
 
 
 
 
 
 
 
 
 
Radisson Hotel & Suites
62,889

 
(29,268
)
 
33,621

 
59,773

 
(29,062
)
 
30,711

Harbor Lakes golf course and country club (a)
—

 
—

 
—

 
2,054

 
(1,508
)
 
546

Income producing properties
 
 
 
 
 
 
 
 
 
 
 
Eleven
53,896

 
(2,861
)
 
51,035

 
53,958

 
(576
)
 
53,382

Midtown (a)
—

 
—

 
—

 
33,293

 
(231
)
 
33,062

Dillon
19,987

 
—

 
19,987

 
15,203

 
—

 
15,203

Music Row
9,947

 
—

 
9,947

 
7,675

 
—

 
7,675

Downtown Edge
12,706

 
—

 
12,706

 
11,856

 
—

 
11,856

West Austin
9,097

 
—

 
9,097

 
8,866

 
—

 
8,866

 
$
618,844

 
$
(32,129
)
 
$
586,715

 
$
607,133

 
$
(31,377
)
 
$
575,756
v3.3.1.900
Oil and Gas Properties and Equipment, net (Tables)
 12 Months Ended
Dec. 31, 2015
Oil and Gas Properties [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
Net capitalized costs, utilizing the successful efforts method of accounting, related to our oil and gas producing activities are as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Unproved leasehold interests
$
19,441

 
$
90,446

Proved oil and gas properties
119,414

 
221,299

Total costs
138,855

 
311,745

Less accumulated depreciation, depletion and amortization
(58,242
)
 
(48,252
)
 
$
80,613

 
$
263,493
v3.3.1.900
Investment in Unconsolidated Ventures (Tables)
 12 Months Ended
Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]  
Summarized Balance Sheet Information
Combined summarized balance sheet information for our ventures accounted for using the equity method follows:
 
Venture Assets
 
Venture Borrowings (a)
 
Venture Equity
 
Our Investment
 
At Year-End
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
242, LLC (b)
$
26,687

 
$
33,021

 
$
—

 
$
6,940

 
$
24,877

 
$
21,789

 
$
11,766

 
$
10,098

CL Ashton Woods, LP (d)
7,654

 
13,269

 
—

 
—

 
6,084

 
11,453

 
3,615

 
6,015

CL Realty, LLC
7,872

 
7,960

 
—

 
—

 
7,662

 
7,738

 
3,831

 
3,869

CREA FMF Nashville LLC (b)
58,002

 
40,014

 
51,028

 
29,660

 
4,291

 
5,987

 
3,820

 
5,516

Elan 99, LLC
34,327

 
10,070

 
14,721

 
1

 
15,838

 
9,643

 
14,255

 
8,679

FMF Littleton LLC
52,528

 
26,953

 
22,499

 
—

 
24,370

 
24,435

 
6,270

 
6,287

FMF Peakview LLC
48,908

 
43,638

 
30,524

 
23,070

 
16,828

 
17,464

 
3,447

 
3,575

FOR/SR Forsyth LLC
6,500

 
—

 
—

 
—

 
6,500

 
—

 
5,850

 
—

HM Stonewall Estates, Ltd. (d)
2,842

 
3,750

 
—

 
669

 
2,842

 
3,081

 
1,294

 
1,752

LM Land Holdings, LP (d)
32,008

 
25,561

 
7,752

 
4,448

 
22,751

 
18,500

 
9,664

 
9,322

MRECV DT Holdings LLC
4,215

 
—

 
—

 
—

 
4,215

 
—

 
3,807

 
—

MRECV Edelweiss LLC
2,237

 
—

 
—

 
—

 
2,237

 
—

 
2,029

 
—

MRECV Juniper Ridge
3,006

 
—

 
—

 
—

 
3,006

 
—

 
2,730

 
—

MRECV Meadow Crossing II LLC
728

 
—

 
—

 
—

 
728

 
—

 
655

 
—

Miramonte Boulder Pass, LLC
12,627

 
—

 
5,869

 
—

 
5,474

 
—

 
5,349

 
—

PSW Communities, LP
—

 
16,045

 
—

 
10,515

 
—

 
4,415

 
—

 
3,924

TEMCO Associates, LLC
5,284

 
11,756

 
—

 
—

 
5,113

 
11,556

 
2,557

 
5,778

Other ventures (e)
4,201

 
8,453

 
2,269

 
26,944

 
1,922

 
(25,614
)
 
1,514

 
190

 
$
309,626

 
$
240,490

 
$
134,662

 
$
102,247

 
$
154,738

 
$
110,447

 
$
82,453

 
$
65,005
Summarized Income Statement Information
Combined summarized income statement information for our ventures accounted for using the equity method follows:
 
Revenues
 
Earnings (Loss)
 
Our Share of Earnings (Loss)
 
For the Year
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
(In thousands)
242, LLC (b)
$
20,995

 
$
5,612

 
$
6,269

 
$
9,588

 
$
2,951

 
$
1,512

 
$
4,919

 
$
1,514

 
$
805

CJUF III, RH Holdings (c)
—

 
2,168

 
120

 
—

 
(956
)
 
(652
)
 
—

 
(956
)
 
(652
)
CL Ashton Woods, LP (d)
9,820

 
5,431

 
9,018

 
3,881

 
1,748

 
2,660

 
5,000

 
2,471

 
4,169

CL Realty, LLC
856

 
1,573

 
1,603

 
424

 
1,068

 
1,028

 
212

 
534

 
514

CREA FMF Nashville LLC (b)
1,227

 
—

 
—

 
(1,696
)
 
(163
)
 
—

 
(1,696
)
 
(163
)
 
—

Elan 99, LLC
—

 
—

 
—

 
(49
)
 
(87
)
 
—

 
(44
)
 
(78
)
 
—

FMF Littleton LLC
120

 
—

 
—

 
(367
)
 
(239
)
 
—

 
(92
)
 
(60
)
 
—

FMF Peakview LLC
2,057

 
4

 
1

 
(1,116
)
 
(410
)
 
(252
)
 
(223
)
 
(83
)
 
(50
)
FOR/SR Forsyth LLC
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

HM Stonewall Estates, Ltd. (d)
3,990

 
1,728

 
2,922

 
1,881

 
613

 
1,082

 
952

 
248

 
452

LM Land Holdings, LP (d)
10,956

 
21,980

 
25,426

 
8,251

 
15,520

 
11,012

 
3,342

 
4,827

 
3,418

MRECV DT Holdings LLC
—

 
—

 
—

 
167

 
—

 
—

 
—

 
—

 
—

MRECV Edelweiss LLC
—

 
—

 
—

 
151

 
—

 
—

 
137

 
—

 
—

MRECV Juniper Ridge
—

 
—

 
—

 
106

 
—

 
—

 
—

 
—

 
—

Miramonte Boulder Pass, LLC
—

 
—

 
—

 
(250
)
 
—

 
—

 
(125
)
 
—

 
—

PSW Communities, LP
29,986

 
—

 
—

 
2,688

 
(86
)
 
—

 
1,169

 
(76
)
 
—

TEMCO Associates, LLC
9,485

 
2,155

 
630

 
2,358

 
494

 
96

 
1,179

 
247

 
48

Other ventures
36,237

 
1,792

 
5,994

 
33,303

 
4,835

 
176

 
1,278

 
260

 
33

 
$
125,729

 
$
42,443

 
$
51,983

 
$
59,320

 
$
25,288

 
$
16,662

 
$
16,008

 
$
8,685

 
$
8,737

_____________________
(a) 
Total includes current maturities of $39,590,000 at year-end 2015, of which $6,798,000 is non-recourse to us, and $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us.
(b) 
Includes unamortized deferred gains on real estate contributed by us to ventures. We recognize deferred gains as income as real estate is sold to third parties. Deferred gains of $1,496,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2015.
(c) 
In 2014, we acquired full ownership in the Eleven venture for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000.
(d) 
Includes unrecognized basis difference of $34,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2015. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.
(e) 
Our investment in other ventures reflects our ownership interests generally ranging from 40 to 75 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.
v3.3.1.900
Receivables (Tables)
 12 Months Ended
Dec. 31, 2015
Receivables [Abstract]  
Receivables
Receivables consist of:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Funds held by qualified intermediary for potential 1031 like-kind exchange
$
14,703

 
$
—

Oil and gas revenue accruals
3,745

 
7,293

Other receivables and accrued interest
2,448

 
6,505

Other loans secured by real estate, average interest rate of 11.31% at year-end 2015 and 4.41% at year-end 2014
2,130

 
1,737

Oil and gas joint interest billing receivables
867

 
5,738

Loan secured by real estate
—

 
3,574

 
23,893

 
24,847

Allowance for bad debts
(237
)
 
(258
)
 
$
23,656

 
$
24,589
Estimated Accretable Yield
Estimated accretable yield is as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Beginning of year
$
839

 
$
8,908

Change in accretable yield due to change in timing of estimated cash flows
30

 
(166
)
Interest income recognized
(869
)
 
(7,903
)
 
$
—

 
$
839
v3.3.1.900
Debt (Tables)
 12 Months Ended
Dec. 31, 2015
Debt Disclosure [Abstract]  
Debt
Debt consists of:
 
At Year-End
 
2015
 
2014
 
(In thousands)
8.50% senior secured notes due 2022
230,560

 
250,000

3.75% convertible senior notes due 2020, net of discount
106,762

 
103,194

6.00% tangible equity units, net of discount
8,768

 
17,154

Secured promissory notes — average interest rates of 3.42% at year-end 2015 and 3.17% at year-end 2014
15,400

 
15,400

Other indebtedness due through 2018 at variable and fixed interest rates ranging from 2.19% to 5.50%
28,292

 
46,996

 
$
389,782

 
$
432,744
v3.3.1.900
Fair Value (Tables)
 12 Months Ended
Dec. 31, 2015
Fair Value Disclosures [Abstract]  
Information About Our Fixed Rate Financial Instruments Not Measured at Fair Value
Information about our fixed rate financial instruments not measured at fair value follows:
 
Year-End 2015
 
Year-End 2014
 
 
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
Valuation
Technique
 
(In thousands)
Recurring Fair Value Measurements:
 
 
 
 
 
 
 
 
 
Loan secured by real estate
$
—

 
$
—

 
$
3,574

 
$
4,859

 
Level 2
Fixed rate debt
$
(346,090
)
 
$
(321,653
)
 
$
(370,348
)
 
$
(359,131
)
 
Level 2
Carrying Value of Assets
 
Year-End 2015
 
Year-End 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Non-recurring Fair Value Measurements:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved oil and gas properties
$
—

 
$
—

 
$
39,000

 
$
39,000

 
$
—

 
$
—

 
$
3,655

 
$
3,655

Unproved leasehold interests
$
—

 
$
—

 
$
18,219

 
$
18,219

 
$
—

 
$
—

 
$
—

 
$
—

Real estate
$
—

 
$
—

 
$
641

 
$
641

 
$
—

 
$
—

 
$
970

 
$
970
v3.3.1.900
Net Income (Loss) per Share (Tables)
 12 Months Ended
Dec. 31, 2015
Earnings Per Share [Abstract]  
Earnings Attributable to Common Shareholders and Weighted Average Common Shares Outstanding
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Numerator:
 
 
 
 
 
Consolidated net income (loss)
$
(212,371
)
 
$
17,088

 
$
35,061

Less: Net (income) attributable to noncontrolling interest
(676
)
 
(505
)
 
(5,740
)
Income (loss) available for diluted earnings per share
$
(213,047
)
 
$
16,583

 
$
29,321

Less: Undistributed net income allocated to participating securities
—

 
(3,018
)
 
(585
)
Income (loss) available to common shareholders for basic earnings per share
$
(213,047
)
 
$
13,565

 
$
28,736

 
 
 
 
 
 
Denominator:
 
 
 
 
 
Weighted average common shares outstanding — basic
34,266

 
35,317

 
35,365

Weighted average common shares upon conversion of participating securities (a)
—

 
7,857

 
835

Dilutive effect of stock options, restricted stock and equity-settled awards
—

 
422

 
613

Total weighted average shares outstanding — diluted
34,266

 
43,596

 
36,813

Anti-dilutive awards excluded from diluted weighted average shares outstanding
10,864

 
2,238

 
1,803


 _____________________
(a)
Our earnings per share calculation reflects the weighted average shares issuable upon settlement of the prepaid stock purchase contract component of our 6.00% tangible equity units, issued in 2013.
v3.3.1.900
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2015
Income Tax Disclosure [Abstract]  
Income Tax Expense
Income tax (expense) benefit consists of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Current tax provision:
 
 
 
 
 
U.S. Federal
$
8,579

 
$
(5,444
)
 
$
(6,004
)
State and other
47

 
(1,569
)
 
(2,066
)
 
8,626

 
(7,013
)
 
(8,070
)
Deferred tax provision:
 
 
 
 
 
U.S. Federal
(38,366
)
 
(2,772
)
 
1,148

State and other
(2,895
)
 
1,128

 
(286
)
 
(41,261
)
 
(1,644
)
 
862

Income tax (expense) benefit
$
(32,635
)
 
$
(8,657
)
 
$
(7,208
)
Reconciliation of Federal Statutory Rate to Effective Income Tax Rate on Continuing Operations
A reconciliation of the federal statutory rate to the effective income tax rate on continuing operations follows:
 
For the Year
 
2015
 
2014
 
2013
Federal statutory rate (benefit)
(35
%)
 
35
 %
 
35
 %
State, net of federal benefit
(1
)
 
1

 
4

Valuation allowance
54

 
—

 
—

Recognition of previously unrecognized tax benefits
—

 
—

 
(15
)
Noncontrolling interests
—

 
—

 
(5
)
Goodwill
—

 
1

 
—

Charitable contributions
—

 
(1
)
 
—

Oil and gas percentage depletion
—

 
(2
)
 
(2
)
Effective tax rate
18
 %
 
34
 %
 
17
 %
Significant Components of Deferred Taxes
Significant components of deferred taxes are:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Deferred Tax Assets:
 
 
 
Real estate
$
69,594

 
$
79,244

Employee benefits
15,752

 
17,352

Net operating loss carryforwards
13,827

 
3,012

Oil and gas properties
5,510

 
—

AMT credits
3,620

 
—

Income producing properties
—

 
364

Oil and gas percentage depletion carryforwards
3,616

 
3,471

Accruals not deductible until paid
911

 
1,111

Other assets
139

 
—

Gross deferred tax assets
112,969

 
104,554

Valuation allowance
(97,068
)
 
(384
)
Deferred tax asset net of valuation allowance
15,901

 
104,170

Deferred Tax Liabilities:
 
 
 
Oil and gas properties
—

 
(49,905
)
Undeveloped land
(7,588
)
 
(4,937
)
Convertible debt
(6,516
)
 
(7,816
)
Income producing properties
(2,257
)
 
—

Timber
(577
)
 
(888
)
Gross deferred tax liabilities
(16,938
)
 
(63,546
)
Net Deferred Tax Asset (Liability)
$
(1,037
)
 
$
40,624
Reconciliation of Beginning and Ending Amount of Tax Benefits Not Recognized for Book Purposes
A reconciliation of the beginning and ending amount of tax benefits not recognized for book purposes is as follows:
 
At Year-End
 
2015
 
2014
 
2013
 
(In thousands)
Balance at beginning of year
$
—

 
$
—

 
$
5,831

Reductions for tax positions of prior years
—

 
—

 
—

Reductions due to lapse of statute of limitations
—

 
—

 
(5,831
)
Balance at end of year that would affect the annual effective tax rate if recognized
$
—

 
$
—

 
$
—
v3.3.1.900
Commitments and Other Contingencies Restructuring (Tables)
 12 Months Ended
Dec. 31, 2015
Restructuring and Related Activities [Abstract]  
Restructuring and Related Costs [Table Text Block]
The following table summarizes activity related to liabilities associated with our oil and gas restructuring activities in 2015:
 
Employee-Related Costs
 
Lease Termination Charge
 
Total
 
(In thousands)
Balance at year-end 2014
$
(2,367
)
 
$
—

 
$
(2,367
)
Additions
(2,047
)
 
(1,750
)
 
(3,797
)
Payments
3,365

 
1,750

 
5,115

Balance at year-end 2015
$
(1,049
)
 
$
—

 
$
(1,049
)
v3.3.1.900
Segment Information (Tables)
 12 Months Ended
Dec. 31, 2015
Segment Reporting [Abstract]  
Segment Revenues and Earnings
 
Real
Estate
 
Oil and Gas
 
Other Natural
Resources
 
Items Not
Allocated to
Segments
 
 
Total
 
(In thousands)
For the year or at year-end 2015
 
 
 
 
 
 
 
 
 
 
Revenues
$
202,830

 
$
52,939

 
$
6,652

 
$
—

  
 
$
262,421

Depreciation, depletion and amortization
7,605

 
28,774

 
540

 
8,166

  
 
45,085

Equity in earnings of unconsolidated ventures
15,582

 
275

 
151

 
—

  
 
16,008

Income (loss) before taxes
67,678

 
(184,396
)
 
(608
)
 
(63,086
)
(a) 
 
(180,412
)
Total assets
691,406

 
144,436

 
19,106

 
125,565

  
 
980,513

Investment in unconsolidated ventures
82,453

 
—

 
—

 
—

  
 
82,453

Capital expenditures (b)
13,644

 
49,776

 
745

 
242

  
 
64,407

For the year or at year-end 2014
 
 
 
 
 
 
 
 
 
 
Revenues
$
213,112

 
$
84,300

 
$
9,362

 
$
—

  
 
$
306,774

Depreciation, depletion and amortization
3,741

 
29,442

 
497

 
8,035

  
 
41,715

Equity in earnings of unconsolidated ventures
8,068

 
586

 
31

 
—

  
 
8,685

Income (loss) before taxes
96,906

 
(22,686
)
 
5,499

 
(54,479
)
(a) 
 
25,240

Total assets
654,774

 
342,703

 
22,531

 
238,191

  
 
1,258,199

Investment in unconsolidated ventures
65,005

 
—

 
—

 
—

  
 
65,005

Capital expenditures (b)
28,980

 
103,385

 
5,817

 
616

  
 
138,798

For the year or at year-end 2013
 
 
 
 
 
 
 
 
 
 
Revenues
$
248,011

 
$
72,313

 
$
10,721

 
$
—

  
 
$
331,045

Depreciation, depletion and amortization
3,117

 
19,552

 
651

 
6,660

  
 
29,980

Equity in earnings of unconsolidated ventures
8,089

 
592

 
56

 
—

  
 
8,737

Income (loss) before taxes
68,454

 
18,859

 
6,507

 
(57,291
)
(a) 
 
36,529

Total assets
582,802

 
312,553

 
23,478

 
253,319

  
 
1,172,152

Investment in unconsolidated ventures
41,147

 
—

 
—

 
—

  
 
41,147

Capital expenditures (b)
7,265

 
97,696

 
2,720

 
216

  
 
107,897

 _____________________
(a) 
Items not allocated to segments consist of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
General and administrative expense
$
(24,802
)
 
$
(21,229
)
 
$
(20,597
)
Share-based and long-term incentive compensation expense
(4,474
)
 
(3,417
)
 
(16,809
)
Interest expense
(34,066
)
 
(30,286
)
 
(20,004
)
Other corporate non-operating income
256

 
453

 
119

 
$
(63,086
)
 
$
(54,479
)
 
$
(57,291
)

(b) 
Consists of expenditures for oil and gas properties and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.
v3.3.1.900
Share-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]  
Components of Share-Based Compensation Expense (Income)
Share-based and long-term incentive compensation expense consists of:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Cash-settled awards
$
(3,127
)
 
$
(3,710
)
 
$
7,774

Equity-settled awards
5,026

 
5,168

 
4,281

Restricted stock
(8
)
 
(25
)
 
538

Stock options
2,355

 
1,984

 
4,216

Total share-based compensation
$
4,246

 
$
3,417

 
$
16,809

Deferred cash
228

 
—

 
—

 
$
4,474

 
$
3,417

 
$
16,809
Share-Based Compensation Expense (Income) Included in Operating Expense
Share-based and long-term incentive compensation expense is included in:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
General and administrative
$
2,451

 
$
1,001

 
$
7,779

Other operating
2,023

 
2,416

 
9,030

 
$
4,474

 
$
3,417

 
$
16,809
Summarized Activity of Cash-Settled Restricted Stock Unit Awards
The following table summarizes the activity of cash-settled restricted stock unit awards in 2015:
 
Equivalent
Units
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
185

 
$18.49
Granted
60

 
13.26
Vested
(117
)
 
18.26
Forfeited
(11
)
 
18.83
Non-vested at end of period
117

 
16.00
Summarized Activity of Cash-Settled Stock Appreciation Rights
The following table summarizes the activity of cash-settled stock appreciation rights in 2015:
 
Rights
Outstanding
 
Weighted Average
Exercise Price
 
Weighted Average
Remaining Contractual Term
 
Aggregate Intrinsic Value
(Current Value Less Exercise Price)
 
(In thousands)
 
(Per share)
 
(In years)
 
(In thousands)
Balance at beginning of period
458

 
$12.54
 
4
 
$1,732
Granted
90

 
14.08
 
 
 
 
Exercised
(39
)
 
9.29
 
 
 
 
Forfeited
(22
)
 
15.00
 
 
 
 
Balance at end of period
487

 
12.97
 
4
 
404
Exercisable at end of period
414

 
12.77
 
3
 
404
Summarized Activity of Equity-Settled Awards
The following table summarizes the activity of equity-settled awards in 2015:
 
Equivalent
Units
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
710

 
$
19.24

Granted
395

 
12.99

Vested
(340
)
 
14.23

Forfeited
(134
)
 
18.18

Non-vested at end of period
631

 
18.25
Schedule of Fair Value Assumptions of MSU Awards
We estimate the grant date fair value of MSU awards using a Monte Carlo simulation pricing model and the following assumptions:
 
 
For the Year
 
 
2015
 
2014
 
2013
Expected stock price volatility
 
32.9
%
 
42.2
%
 
42.2
%
Risk-free interest rate
 
1.0
%
 
0.7
%
 
0.4
%
Expected dividend yield
 
—
%
 
—
%
 
—
%
Weighted average grant date fair value of MSU awards (per unit)
 
$
15.11

 
$
20.38

 
$
21.09
Summarized Activity of Restricted Stock Awards
The following table summarizes the activity of restricted stock awards in 2015:
 
Restricted
Shares
 
Weighted Average Grant Date Fair Value
 
(In thousands)
 
(Per unit)
Non-vested at beginning of period
17

 
$
17.56

Granted
—

 
—

Vested
(7
)
 
14.59

Forfeited
(6
)
 
19.00

Non-vested at end of period
4

 
20.55
Summarized Activity of Stock Option Awards
The following table summarizes the activity of stock option awards in 2015:
 
Options
Outstanding
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Term
 
Aggregate
Intrinsic Value
(Current
Value Less
Exercise Price)
 
(In thousands)
 
(Per share)
 
(In years)
 
(In thousands)
Balance at beginning of period
1,861

 
$
20.74

 
6
 
$
643

Granted
413

 
13.86

 
 
 
 
Exercised
—

 
—

 
 
 
 
Forfeited
(103
)
 
18.01

 
 
 
 
Balance at end of period
2,171

 
19.56

 
5
 
156

Exercisable at end of period
1,687

 
20.83

 
4
 
156
Schedule of Fair Value Assumptions of Stock Options
We estimated the fair value of these options with market conditions using Monte Carlo simulation pricing model and the following assumptions:
 
 
For the Year
 
 
2015
Expected stock price volatility
 
61.4
%
Risk-free interest rate
 
2.2
%
Expected dividend yield
 
—
%
Weighted average grant date fair value of options (per share)
 
$
7.87

We estimate the grant date fair value of stock options that do not have a market condition using the Black-Scholes option pricing model and the following assumptions:
 
 
For the Year
 
 
2015
 
2013
Expected stock price volatility
 
45.6
%
 
66.8
%
Risk-free interest rate
 
1.8
%
 
1.4
%
Expected life of options (years)
 
6

 
6

Expected dividend yield
 
—
%
 
—
%
Weighted average grant date fair value of options (per share)
 
$
6.51

 
$
11.47
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2015
Summary of Estimated Quantities of Proved Developed Oil and Natural Gas Reserves
Estimated quantities of proved oil and gas reserves are summarized as follows:
 
Reserves
 
Oil (a)
(Barrels)
 
Gas
(Mcf)
 
(In thousands)
Consolidated entities:
 
 
 
Year-end 2012
3,220

 
11,722

Revisions of previous estimates
182

 
1,243

Extensions and discoveries
3,085

 
2,046

Acquisitions
35

 
531

Production
(698
)
 
(1,912
)
Year-end 2013
5,824

 
13,630

Revisions of previous estimates
608

 
293

Extensions and discoveries
2,191

 
774

Acquisitions
85

 
31

Sales
(105
)
 
(218
)
Production
(931
)
 
(1,861
)
Year-end 2014
7,672

 
12,649

Revisions of previous estimates
(855
)
 
(1,675
)
Extensions and discoveries
224

 
173

Acquisitions
—

 
—

Sales
(704
)
 
(1,223
)
Production
(1,158
)
 
(1,967
)
Year-end 2015
5,179

 
7,957

Our share of ventures accounted for using the equity method:
 
 
 
Year-end 2012
—

 
2,572

Revisions of previous estimates
—

 
7

Production
—

 
(247
)
Year-end 2013
—

 
2,332

Revisions of previous estimates
—

 
(382
)
Production
—

 
(199
)
Year-end 2014
—

 
1,751

Revisions of previous estimates
—

 
(320
)
Production
—

 
(168
)
Year-end 2015
—

 
1,263

Total consolidated and our share of equity method ventures:
 
 
 
Year-end 2013
 
 
 
Proved developed reserves
3,893

 
13,717

Proved undeveloped reserves
1,931

 
2,245

Total Year-end 2013
5,824

 
15,962

Year-end 2014
 
 
 
Proved developed reserves
5,269

 
12,599

Proved undeveloped reserves
2,403

 
1,801

Total Year-end 2014
7,672

 
14,400

Year-end 2015
 
 
 
Proved developed reserves
5,179

 
9,220

Proved undeveloped reserves
—

 
—

Total Year-end 2015
5,179

 
9,220
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
Net capitalized costs, utilizing the successful efforts method of accounting, related to our oil and gas producing activities are as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Unproved leasehold interests
$
19,441

 
$
90,446

Proved oil and gas properties
119,414

 
221,299

Total costs
138,855

 
311,745

Less accumulated depreciation, depletion and amortization
(58,242
)
 
(48,252
)
 
$
80,613

 
$
263,493
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities:
 
 
 
 
 
Acquisition costs
 
 
 
 
 
Proved properties
$
—

 
$
2,001

 
$
—

Unproved properties
4,832

 
25,666

 
35,806

Exploration costs
17,922

 
39,399

 
10,486

Development costs
27,609

 
40,277

 
54,538

 
$
50,363

 
$
107,343

 
$
100,830
Estimates of Future Cash Flows from Proved Developed Oil and Natural Gas Reserves
Estimates of future cash flows from proved oil and gas reserves are shown in the following table. Estimated income taxes are calculated by applying the appropriate tax rates to the estimated future pre-tax net cash flows less depreciation of the tax basis of properties and the statutory depletion allowance.
 
At Year-End
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities:
 
 
 
 
 
Future cash inflows
$
216,588

 
$
665,657

 
$
544,098

Future production and development costs
(93,623
)
 
(271,735
)
 
(231,801
)
Future income tax expenses
(22,218
)
 
(106,002
)
 
(77,361
)
Future net cash flows
100,747

 
287,920

 
234,936

10% annual discount for estimated timing of cash flows
(33,951
)
 
(124,079
)
 
(99,383
)
Standardized measure of discounted future net cash flows
$
66,796

 
$
163,841

 
$
135,553

Our share in ventures accounted for using the equity method:
 
 
 
 
 
Future cash inflows
$
2,283

 
$
6,186

 
$
4,765

Future production and development costs
(245
)
 
(664
)
 
(512
)
Future income tax expenses
(774
)
 
(2,098
)
 
(1,616
)
Future net cash flows
1,264

 
3,424

 
2,637

10% annual discount for estimated timing of cash flows
(562
)
 
(1,649
)
 
(1,337
)
Standardized measure of discounted future net cash flows
$
702

 
$
1,775

 
$
1,300

Total consolidated and our share of equity method ventures
$
67,498

 
$
165,616

 
$
136,853
Changes in Standardized Measure of Discounted Future Net Cash Flow
Changes in the standardized measure of discounted future net cash flow follows:
 
For the Year
 
Consolidated
 
Our Share of Equity
Method Ventures
 
Total
 
(In thousands)
Year-end 2012
$
106,543

 
$
1,413

 
$
107,956

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
23,422

 
415

 
23,837

Net change in future development costs
(2,897
)
 
—

 
(2,897
)
Sales of oil and gas, net of production costs
(56,559
)
 
(801
)
 
(57,360
)
Net change due to extensions and discoveries
54,539

 
—

 
54,539

Net change due to acquisition of reserves
1,160

 
—

 
1,160

Net change due to revisions of quantity estimates
8,673

 
6

 
8,679

Previously estimated development costs incurred
4,124

 
—

 
4,124

Accretion of discount
13,540

 
228

 
13,768

Net change in timing and other
(718
)
 
(31
)
 
(749
)
Net change in income taxes
(16,274
)
 
70

 
(16,204
)
Aggregate change for the year
29,010

 
(113
)
 
28,897

Year-end 2013
135,553

 
1,300

 
136,853

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
(1,064
)
 
1,571

 
507

Net change in future development costs
1,308

 
—

 
1,308

Sales of oil and gas, net of production costs
(63,192
)
 
(787
)
 
(63,979
)
Net change due to extensions and discoveries
58,228

 
—

 
58,228

Net change due to acquisition of reserves
2,778

 
—

 
2,778

Net change due to divestitures of reserves
(5,804
)
 
—

 
(5,804
)
Net change due to revisions of quantity estimates
15,303

 
(343
)
 
14,960

Previously estimated development costs incurred
15,497

 
—

 
15,497

Accretion of discount
18,067

 
210

 
18,277

Net change in timing and other
4,198

 
115

 
4,313

Net change in income taxes
(17,031
)
 
(291
)
 
(17,322
)
Aggregate change for the year
28,288

 
475

 
28,763

Year-end 2014
163,841

 
1,775

 
165,616

Changes resulting from:
 
 
 
 
 
Net change in sales prices and production costs
(136,536
)
 
(1,112
)
 
(137,648
)
Net change in future development costs
92

 
—

 
92

Sales of oil and gas, net of production costs
(31,732
)
 
(428
)
 
(32,160
)
Net change due to extensions and discoveries
11,747

 
—

 
11,747

Net change due to acquisition of reserves
—

 
—

 
—

Net change due to divestitures of reserves
(15,855
)
 
 
 
(15,855
)
Net change due to revisions of quantity estimates
(15,164
)
 
(267
)
 
(15,431
)
Previously estimated development costs incurred
15,096

 
—

 
15,096

Accretion of discount
22,600

 
286

 
22,886

Net change in timing and other
4,018

 
(210
)
 
3,808

Net change in income taxes
48,689

 
658

 
49,347

Aggregate change for the year
(97,045
)
 
(1,073
)
 
(98,118
)
Year-end 2015
$
66,796

 
$
702

 
$
67,498
Information About Results of Operations of Oil and Natural Gas Interests
Information about the results of operations of our oil and gas interests follows:
 
For the Year
 
2015
 
2014
 
2013
 
(In thousands)
Consolidated entities
 
 
 
 
 
Revenues
$
51,553

 
$
82,919

 
$
69,036

Production costs
(19,820
)
 
(19,727
)
 
(12,477
)
Exploration costs
(11,864
)
 
(17,416
)
 
(10,486
)
Depreciation, depletion, amortization
(28,774
)
 
(29,442
)
 
(19,552
)
Non-cash impairment of proved oil and gas properties and unproved leasehold interests
(164,831
)
 
(32,665
)
 
(473
)
Oil and gas administrative expenses
(11,700
)
 
(17,000
)
 
(14,407
)
Accretion expense
(144
)
 
(121
)
 
(94
)
Income tax expenses
14,717

 
13,398

 
(3,471
)
Results of operations
(170,863
)
 
(20,054
)
 
8,076

Our share in ventures accounted for using the equity method:
 
 
 
 
 
Revenues
$
428

 
$
786

 
$
801

Production costs
(102
)
 
(105
)
 
(123
)
Oil and gas administrative expenses
(51
)
 
(95
)
 
(86
)
Income tax expenses
21

 
(235
)
 
(178
)
Results of operations
$
296

 
$
351

 
$
414

Total results of operations
$
(170,567
)
 
$
(19,703
)
 
$
8,490
Consolidated Entities [Member]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
Capitalized costs related to our oil and gas producing activities are as follows:
 
At Year-End
 
2015
 
2014
 
(In thousands)
Consolidated entities:
 
 
 
Unproved oil and gas properties
$
19,441

 
$
90,446

Proved oil and gas properties
119,414

 
221,299

Total costs
138,855

 
311,745

Less accumulated depreciation, depletion and amortization
(58,242
)
 
(48,252
)
 
$
80,613

 
$
263,493
v3.3.1.900
Summary of Quarterly Results of Operations (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]  
Summary of Quarterly Results of Operations
Summarized quarterly financial results for 2015 and 2014 follows:
 
First Quarter (a)
 
Second Quarter (a)
 
Third
    Quarter (a)
 
Fourth
    Quarter (a)
 
(In thousands, except per share amounts)
2015
 
 
 
 
 
 
 
Total revenues
$
47,805

 
$
57,430

 
$
43,168

 
$
114,018

Gross profit (loss)
17,289

 
(35,009
)
 
(69,572
)
 
8,341

Operating income (loss)
(7,737
)
 
(52,714
)
 
(94,751
)
 
(9,482
)
Equity in earnings of unconsolidated ventures
3,045

 
5,584

 
2,909

 
4,470

Income (loss) before taxes
(12,596
)
 
(55,062
)
 
(100,095
)
 
(11,983
)
Net income (loss) attributable to Forestar Group Inc.
(8,158
)
 
(34,507
)
 
(164,216
)
 
(6,166
)
 
 
 
 
 
 
 
 
Net income (loss) per share — basic
$
(0.24
)
 
$
(1.01
)
 
$
(4.79
)
 
$
(0.18
)
Net income (loss) per share — diluted
$
(0.24
)
 
$
(1.01
)
 
$
(4.79
)
 
$
(0.18
)
 
 
 
 
 
 
 
 
2014
 
 
 
 
 
 
 
Total revenues
$
84,605

 
$
83,013

 
$
58,840

 
$
80,316

Gross profit (loss)
35,025

 
33,261

 
19,606

 
(6,259
)
Operating income (loss)
15,883

 
26,942

 
12,716

 
(16,783
)
Equity in earnings of unconsolidated ventures
991

 
958

 
2,016

 
4,720

Income (loss) before taxes
13,665

 
22,799

 
7,994

 
(18,713
)
Net income (loss) attributable to Forestar Group Inc.
8,334

 
14,822

 
5,227

 
(11,800
)
 
 
 
 
 
 
 
 
Net income (loss) per share — basic
$
0.20

 
$
0.34

 
$
0.12

 
$
(0.34
)
Net income (loss) per share — diluted
$
0.19

 
$
0.34

 
$
0.12

 
$
(0.34
)
 _____________________
(a)Non-cash impairment charges for unproved leasehold interests and proved oil and gas properties included in our quarterly financial results are as follows:
 
First Quarter
 
Second Quarter
 
Third
Quarter
 
Fourth
Quarter
 
(In thousands)
2015
$
7

 
$
45,938

 
$
81,240

 
$
37,646

2014
755

 
584

 
735

 
30,591
v3.3.1.900
Summary of Significant Accounting Policies - Additional Information (Detail)
a in Thousands
 12 Months Ended
Dec. 31, 2015
USD ($)
a
Dec. 31, 2014
USD ($)
Dec. 31, 2013
USD ($)
Significant Accounting Policies [Line Items]      
Capitalized Exploratory Well Costs $ 0 $ 8,575,000  
Capitalized Exploratory Well Cost, Charged to Expense 8,454,000    
Capital Expenditures Incurred but Not yet Paid 7,033,000 19,405,000  
Restricted cash and cash equivalents $ 200,000 217,000  
Contractual Period Of Sale Contracts 5 years    
Non-Oil And Gas Properties [Member]      
Significant Accounting Policies [Line Items]      
Depreciation expense of property and equipment $ 1,067,000 903,000 $ 1,028,000
Minimum [Member]      
Significant Accounting Policies [Line Items]      
Reimbursement range on water, sewer and other infrastructure-related assets 70.00%    
Maximum [Member]      
Significant Accounting Policies [Line Items]      
Reimbursement range on water, sewer and other infrastructure-related assets 90.00%    
Capitalize reforestation costs 2 years    
Computer Software, Intangible Asset [Member]      
Significant Accounting Policies [Line Items]      
Carrying value of capitalized software $ 237,000 1,188,000  
Capitalized software amortization $ 996,000 1,067,000 1,593,000
Computer Software, Intangible Asset [Member] | Minimum [Member]      
Significant Accounting Policies [Line Items]      
Useful life range 3 years    
Computer Software, Intangible Asset [Member] | Maximum [Member]      
Significant Accounting Policies [Line Items]      
Useful life range 5 years    
Georgia [Member]      
Significant Accounting Policies [Line Items]      
Timber owned directly or through ventures | a 89    
Depletion $ 250,000 $ 371,000 $ 609,000
v3.3.1.900
Summary of Significant Accounting Policies - Schedule of Change in Asset Retirement Obligation (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Asset Retirement Obligation [Roll Forward]    
Beginning balance $ 1,807 $ 1,483
Accretion expense 144 122
Additions 65 314
Asset Retirement Obligation, Liabilities Settled (119) (230)
Asset Retirement Obligation, Revision of Estimate 0 118
Asset Retirement Obligation, Cash Paid to Settle 139 0
Ending balance $ 1,758 $ 1,807
v3.3.1.900
Summary of Significant Accounting Policies - Estimated Useful Lives of Property Plant and Equipment (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Property, Plant and Equipment [Line Items]    
Property plant and equipment, gross $ 16,274 $ 18,545
Less: accumulated depreciation (5,542) (6,918)
Property Plant And Equipment, Net 10,732 11,627
Building and Building Improvements [Member]    
Property, Plant and Equipment [Line Items]    
Property plant and equipment, gross 4,044 4,461
Property and Equipment [Member]    
Property, Plant and Equipment [Line Items]    
Property plant and equipment, gross $ 12,230 $ 14,084
Minimum [Member] | Building and Building Improvements [Member]    
Property, Plant and Equipment [Line Items]    
Property plant and equipment, useful life 10 years  
Minimum [Member] | Property and Equipment [Member]    
Property, Plant and Equipment [Line Items]    
Property plant and equipment, useful life 2 years  
Maximum [Member] | Building and Building Improvements [Member]    
Property, Plant and Equipment [Line Items]    
Property plant and equipment, useful life 40 years  
Maximum [Member] | Property and Equipment [Member]    
Property, Plant and Equipment [Line Items]    
Property plant and equipment, useful life 10 years  
v3.3.1.900
Goodwill and Other Intangible Assets - Carrying Value of Goodwill and Other Intangible Assets (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]    
Goodwill $ 61,164 $ 63,423
Identified intangibles, net 1,964 2,708
Total $ 63,128 $ 66,131
v3.3.1.900
Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($)
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2010
Schedule Of Goodwill And Other Intangible Assets [Line Items]      
Goodwill acquired on acquisition $ 61,164,000 $ 63,423,000  
Oil and Gas Properties [Member]      
Schedule Of Goodwill And Other Intangible Assets [Line Items]      
Goodwill acquired on acquisition 57,290,000 59,549,000  
Water Resources Company [Member]      
Schedule Of Goodwill And Other Intangible Assets [Line Items]      
Goodwill acquired on acquisition   3,874,000  
Water Resources Company [Member] | Groundwater Leases [Member]      
Schedule Of Goodwill And Other Intangible Assets [Line Items]      
Identified intangible assets     $ 1,681,000
Patents [Member] | Credo [Member]      
Schedule Of Goodwill And Other Intangible Assets [Line Items]      
Identified intangibles, net $ 283,000    
Multi Family Property [Member] | Austin, Texas [Member]      
Schedule Of Goodwill And Other Intangible Assets [Line Items]      
Identified intangibles, net   $ 865,000  
v3.3.1.900
Real Estate - Real Estate (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Real Estate Properties [Line Items]        
Accumulated depreciation $ (32,129) $ (31,377) $ (28,066) $ (28,220)
SEC Schedule III, Real Estate, Gross 618,844 607,133 $ 547,530 $ 545,370
Total Real Estate 586,715 575,756    
West Austin [Member]        
Real Estate Properties [Line Items]        
Carrying value 9,097 8,866    
Accumulated depreciation 0 0    
Net carrying value 9,097 8,866    
Downtown Edge [Member]        
Real Estate Properties [Line Items]        
Carrying value 12,706 11,856    
Accumulated depreciation 0 0    
Net carrying value 12,706 11,856    
Music Row [Member]        
Real Estate Properties [Line Items]        
Carrying value 9,947 7,675    
Accumulated depreciation 0 0    
Net carrying value 9,947 7,675    
Dillon [Member]        
Real Estate Properties [Line Items]        
Carrying value 19,987 15,203    
Accumulated depreciation 0 0    
Net carrying value 19,987 15,203    
Midtown [Member]        
Real Estate Properties [Line Items]        
Carrying value 0 [1] 33,293    
Accumulated depreciation 0 [1] (231)    
Net carrying value 0 [1] 33,062    
Eleven [Member]        
Real Estate Properties [Line Items]        
Carrying value 53,896 53,958    
Accumulated depreciation (2,861) (576)    
Net carrying value 51,035 53,382    
Harbor Lakes [Member]        
Real Estate Properties [Line Items]        
Carrying value 0 [1] 2,054    
Accumulated depreciation 0 [1] (1,508)    
Net carrying value 0 [1] 546    
Radisson Hotel [Member]        
Real Estate Properties [Line Items]        
Carrying value 62,889 59,773    
Accumulated depreciation (29,268) (29,062)    
Net carrying value 33,621 30,711    
Undeveloped land (includes land in entitlement) [Member] [Member]        
Real Estate Properties [Line Items]        
Carrying value 98,181 93,182    
Accumulated depreciation 0 0    
Net carrying value 98,181 93,182    
Entitled, developed and under development projects [Member]        
Real Estate Properties [Line Items]        
Carrying value 352,141 321,273    
Accumulated depreciation 0 0    
Net carrying value $ 352,141 $ 321,273    
[1] Sold in 2015.
v3.3.1.900
Real Estate - Additional Information (Detail)
 12 Months Ended 108 Months Ended
Dec. 31, 2015
USD ($)
Property
Dec. 31, 2014
USD ($)
Property
Dec. 31, 2013
USD ($)
Dec. 31, 2015
USD ($)
Property
Sep. 30, 2014
USD ($)
Real Estate Properties [Line Items]          
Costs relate to water, sewer and other infrastructure assets       $ 54,376,000  
Recovery of direct costs $ (15,176,000) $ (66,047,000) $ (9,945,000)    
GAIN ON SALE OF ASSETS 879,000 38,038,000 5,161,000    
Investment in resort development 586,715,000 575,756,000   586,715,000  
General Contractor Costs 1,543,000 5,111,000 554,000    
Non-cash asset impairment charges 108,184,000 15,934,000 1,790,000    
Payments to Acquire and Develop Real Estate 107,988,000 114,694,000 106,609,000    
Cibolo Canyons Project [Member]          
Real Estate Properties [Line Items]          
Recovery of direct costs       34,703,000  
Payments Received From Special Improvement District 425,000        
GAIN ON SALE OF ASSETS 1,160,000 6,577,000      
Investment in resort development         $ 24,067,000
Cibolo Canyons Project [Member] | San Antonio Texas [Member]          
Real Estate Properties [Line Items]          
Cost of asset in developed and under development projects $ 22,302,000 31,913,000   $ 22,302,000  
Multi Family Property [Member] | Austin, Texas [Member]          
Real Estate Properties [Line Items]          
Carrying value   $ 53,917,000      
Number Of Units Of Multifamily Project | Property 257 257   257  
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage   25.00%      
Payments to Acquire Businesses and Interest in Affiliates   $ 21,500,000      
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net   55,275,000      
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt   23,936,000      
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value   2,229,000      
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value   9,839,000      
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain   7,610,000      
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets   992,000      
Identified intangibles, net   865,000      
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Working Capital   979,000      
Consolidated Properties [Member]          
Real Estate Properties [Line Items]          
Recovery of direct costs $ 14,751,000        
Utility and Improvement District [Member]          
Real Estate Properties [Line Items]          
Cost of asset in developed and under development projects 67,554,000 65,212,000   $ 67,554,000  
Income Producing Properties [Member] | Land, Buildings and Improvements [Member]          
Real Estate Properties [Line Items]          
Depreciation expense, related to commercial and income producing properties 6,810,000 3,319,000 $ 2,507,000    
Real Estate [Member]          
Real Estate Properties [Line Items]          
Non-cash asset impairment charges 1,044,000 399,000      
Bonds [Member] | Cibolo Canyons Project [Member]          
Real Estate Properties [Line Items]          
Payments Received From Special Improvement District 46,500,000 50,550,000      
Debt Instrument, Face Amount 48,900,000     48,900,000  
Letters of Credit Outstanding, Amount 6,846,000     6,846,000  
Surety Bond for Bond Trustee 7,850,000     7,850,000  
Midtown [Member]          
Real Estate Properties [Line Items]          
Carrying value $ 0 [1] $ 33,293,000   $ 0 [1]  
Number Of Units Of Multifamily Project | Property 354     354  
Real Estate Property Sale Price $ 42,880,000        
Segment Earnings From Sale of Multifamily Property 9,265,000        
Proceeds from sale of multifamily property 18,473,000        
Repayments of Debt $ 24,166,000        
[1] Sold in 2015.
v3.3.1.900
Oil and Gas Properties and Equipment, net (Details)
 3 Months Ended 12 Months Ended
Dec. 31, 2015
USD ($)
a
Well
Sep. 30, 2015
USD ($)
Jun. 30, 2015
USD ($)
Mar. 31, 2015
USD ($)
Dec. 31, 2014
USD ($)
Sep. 30, 2014
USD ($)
Jun. 30, 2014
USD ($)
Mar. 31, 2014
USD ($)
Dec. 31, 2015
USD ($)
a
Well
Dec. 31, 2014
USD ($)
Impairment of Oil and Gas Properties $ 37,646,000 $ 81,240,000 $ 45,938,000 $ 7,000 $ 30,591,000 $ 735,000 $ 584,000 $ 755,000 $ 164,831,000 $ 32,665,000
Impairment of Leasehold                 57,691,000 17,130,000
Impairment of Oil and Gas Properties                 107,140,000 $ 15,535,000
Loss on Disposition of Proved Property                 706,000  
Proceeds from Sale of Oil and Gas Property and Equipment                 $ 17,800,000  
Transaction [Domain]                    
Gas and Oil Area, Undeveloped, Net | a 109,000               109,000  
Productive Oil Wells, Number of Wells, Gross | Well 39               39  
Productive Oil Wells, Number of Wells, Net | Well 7               7  
v3.3.1.900
Oil and Gas Properties and Equipment, net Properties and Equipment, net - Net Capitalized Costs Related to Oil and Gas Producing Activities (Details) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Oil and Gas Properties [Abstract]    
Unproved oil and gas properties $ 19,441 $ 90,446
Proved Oil and Gas Property, Successful Effort Method 119,414 221,299
Total costs 138,855 311,745
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion and Amortization (58,242) (48,252)
Oil and Gas Property, Successful Effort Method, Net $ 80,613 $ 263,493
v3.3.1.900
Investment In Unconsolidated Ventures - Additional Information (Detail)
 12 Months Ended
Dec. 31, 2015
USD ($)
Property
Venture
Dec. 31, 2014
USD ($)
Property
Dec. 31, 2013
USD ($)
Payments to Acquire Additional Interest in Subsidiaries $ 0 $ 7,971,000 $ 0
Noncontrolling interests 0 2,904,000 2,907,000
Investment in unconsolidated ventures $ 82,453,000 65,005,000 41,147,000
Number of ventures under ownership interest using equity method | Venture 20    
Payments to Acquire Interest in Joint Venture $ 0 20,155,000  
Distributions 24,909,000 7,518,000 9,854,000
Fees for services 1,856,000 2,275,000 1,068,000
Equity Method Investee [Member]      
Payments to Acquire Interest in Joint Venture 26,349,000 14,692,000 857,000
FMF Littleton [Member]      
Construction Loan [1] 22,499,000    
Investment in unconsolidated ventures 6,270,000 6,287,000  
CREA FMF [Member]      
Investment in unconsolidated ventures [2] 3,820,000 5,516,000  
Elan 99 LLC [Member]      
Investment in unconsolidated ventures 14,255,000 8,679,000  
Construction Loans [Member] | CREA FMF [Member] | Nashville, Tennessee [Member]      
Construction Loan [1],[2] 51,028,000    
Construction Loans [Member] | Elan 99 LLC [Member] | Houston, Texas [Member]      
Construction Loan [1] $ 14,721,000    
Multi Family Property [Member]      
Payments to Acquire Interest in Joint Venture     $ 0
Multi Family Property [Member] | Austin, Texas [Member]      
Payments to Acquire Additional Interest in Subsidiaries   $ 21,500,000  
Number Of Units Of Multifamily Project | Property 257 257  
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net   $ 55,275,000  
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt   23,936,000  
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value   $ 2,229,000  
[1] Total includes current maturities of $39,590,000 at year-end 2015, of which $6,798,000 is non-recourse to us, and $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us.
[2] Includes unamortized deferred gains on real estate contributed by us to ventures. We recognize deferred gains as income as real estate is sold to third parties. Deferred gains of $1,496,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2015.
v3.3.1.900
Investment In Unconsolidated Ventures - Summarized Balance Sheet Information (Detail) - USD ($)
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]      
Venture Assets $ 309,626,000 $ 240,490,000  
Venture Borrowings [1] 134,662,000 102,247,000  
Venture Equity 154,738,000 110,447,000  
Investment in unconsolidated ventures 82,453,000 65,005,000 $ 41,147,000
242, LLC [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets [2] 26,687,000 33,021,000  
Venture Borrowings [1],[2] 0 6,940,000  
Venture Equity [2] 24,877,000 21,789,000  
Investment in unconsolidated ventures [2] 11,766,000 10,098,000  
Elan 99 LLC [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 34,327,000 10,070,000  
Venture Borrowings [1]   1,000  
Venture Equity 15,838,000 9,643,000  
Investment in unconsolidated ventures 14,255,000 8,679,000  
CL Ashton Woods [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets [3] 7,654,000 13,269,000  
Venture Borrowings [1],[3] 0 0  
Venture Equity [3] 6,084,000 11,453,000  
Investment in unconsolidated ventures [3] 3,615,000 6,015,000  
CL Realty [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 7,872,000 7,960,000  
Venture Borrowings [1] 0 0  
Venture Equity 7,662,000 7,738,000  
Investment in unconsolidated ventures 3,831,000 3,869,000  
CREA FMF [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets [2] 58,002,000 40,014,000  
Venture Borrowings [1],[2]   29,660,000  
Venture Equity [2] 4,291,000 5,987,000  
Investment in unconsolidated ventures [2] 3,820,000 5,516,000  
FMF Littleton [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 52,528,000 26,953,000  
Construction Loan [1] 22,499,000    
Venture Borrowings [1]   0  
Venture Equity 24,370,000 24,435,000  
Investment in unconsolidated ventures 6,270,000 6,287,000  
FMF Peakview [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 48,908,000 43,638,000  
Venture Borrowings [1] 30,524,000 23,070,000  
Venture Equity 16,828,000 17,464,000  
Investment in unconsolidated ventures 3,447,000 3,575,000  
FOR/SR Forsyth LLC [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 6,500,000 0  
Venture Borrowings 0 0  
Venture Equity 6,500,000 0  
Investment in unconsolidated ventures 5,850,000 0  
HM Stonewall Estates [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets [3] 2,842,000 3,750,000  
Venture Borrowings [1],[3] 0 669,000  
Venture Equity [3] 2,842,000 3,081,000  
Investment in unconsolidated ventures [3] 1,294,000 1,752,000  
LM Land Holdings [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets [3] 32,008,000 25,561,000  
Venture Borrowings [1],[3] 7,752,000 4,448,000  
Venture Equity [3] 22,751,000 18,500,000  
Investment in unconsolidated ventures [3] 9,664,000 9,322,000  
MRECV DT Holdings LLC [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 4,215,000 0  
Venture Borrowings [1] 0 0  
Venture Equity 4,215,000 0  
Investment in unconsolidated ventures 3,807,000 0  
MRECV Edelweiss LLC [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 2,237,000 0  
Venture Borrowings [1] 0 0  
Venture Equity 2,237,000 0  
Investment in unconsolidated ventures 2,029,000 0  
MRECV Juniper Ridge LLC [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 3,006,000 0  
Venture Borrowings [1] 0 0  
Venture Equity 3,006,000 0  
Investment in unconsolidated ventures 2,730,000 0  
MRECV Meadow Crossing II LLC [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 728,000 0  
Venture Borrowings [1] 0 0  
Venture Equity 728,000 0  
Investment in unconsolidated ventures 655,000 0  
Miramonte Boulder Pass, LLC [Member] [Domain]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 12,627,000 0  
Venture Borrowings [1] 5,869,000 0  
Venture Equity 5,474,000 0  
Investment in unconsolidated ventures 5,349,000 0  
PSW Communities [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 0 16,045,000  
Venture Borrowings [1] 0 10,515,000  
Venture Equity 0 4,415,000  
Investment in unconsolidated ventures 0 3,924,000  
Temco [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets 5,284,000 11,756,000  
Venture Borrowings [1] 0 0  
Venture Equity 5,113,000 11,556,000  
Investment in unconsolidated ventures 2,557,000 5,778,000  
Other Ventures [Member]      
Schedule of Equity Method Investments [Line Items]      
Venture Assets [4] 4,201,000 8,453,000  
Venture Borrowings [1],[4] 2,269,000 26,944,000  
Venture Equity [4] 1,922,000 (25,614,000)  
Investment in unconsolidated ventures [4] $ 1,514,000 $ 190,000  
[1] Total includes current maturities of $39,590,000 at year-end 2015, of which $6,798,000 is non-recourse to us, and $65,795,000 at year-end 2014, of which $42,566,000 is non-recourse to us.
[2] Includes unamortized deferred gains on real estate contributed by us to ventures. We recognize deferred gains as income as real estate is sold to third parties. Deferred gains of $1,496,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2015.
[3] Includes unrecognized basis difference of $34,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2015. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.
[4] Our investment in other ventures reflects our ownership interests generally ranging from 40 to 75 percent, excluding venture losses that exceed our investment where we are not obligated to fund those losses. Please read Note 16 — Variable Interest Entities for additional information.
v3.3.1.900
Investment In Unconsolidated Ventures - Summarized Income Statement Information (Detail) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2015
 [1]
Sep. 30, 2015
 [1]
Jun. 30, 2015
 [1]
Mar. 31, 2015
 [1]
Dec. 31, 2014
 [1]
Sep. 30, 2014
 [1]
Jun. 30, 2014
 [1]
Mar. 31, 2014
 [1]
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]                      
Revenues                 $ 125,729 $ 42,443 $ 51,983
Earnings (Loss)                 59,320 25,288 16,662
Our share of earnings (loss) $ 4,470 $ 2,909 $ 5,584 $ 3,045 $ 4,720 $ 2,016 $ 958 $ 991 16,008 8,685 8,737
242, LLC [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues [2]                 20,995 5,612 6,269
Earnings (Loss) [2]                 9,588 2,951 1,512
Our share of earnings (loss) [2]                 4,919 1,514 805
CJUF III, RH Holdings [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues [3]                 0 2,168 120
Earnings (Loss) [3]                 0 (956) (652)
Our share of earnings (loss) [3]                 0 (956) (652)
CL Ashton Woods [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues [4]                 9,820 5,431 9,018
Earnings (Loss) [4]                 3,881 1,748 2,660
Our share of earnings (loss) [4]                 5,000 2,471 4,169
CL Realty [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 856 1,573 1,603
Earnings (Loss)                 424 1,068 1,028
Our share of earnings (loss)                 212 534 514
CREA FMF [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues [2]                 1,227 0 0
Earnings (Loss) [2]                 (1,696) (163) 0
Our share of earnings (loss) [2]                 (1,696) (163) 0
Elan 99 LLC [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 0 0 0
Earnings (Loss)                 (49) (87) 0
Our share of earnings (loss)                 (44) (78) 0
FMF Littleton [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 120 0 0
Earnings (Loss)                 (367) (239) 0
Our share of earnings (loss)                 (92) (60) 0
FMF Peakview [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 2,057 4 1
Earnings (Loss)                 (1,116) (410) (252)
Our share of earnings (loss)                 (223) (83) (50)
FOR/SR Forsyth LLC [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 0 0 0
Earnings (Loss)                 0 0 0
Our share of earnings (loss)                 0 0 0
HM Stonewall Estates [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues [4]                 3,990 1,728 2,922
Earnings (Loss) [4]                 1,881 613 1,082
Our share of earnings (loss) [4]                 952 248 452
LM Land Holdings [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues [4]                 10,956 21,980 25,426
Earnings (Loss) [4]                 8,251 15,520 11,012
Our share of earnings (loss) [4]                 3,342 4,827 3,418
MRECV DT Holdings LLC [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 0 0 0
Earnings (Loss)                 167 0 0
Our share of earnings (loss)                 0 0 0
MRECV Edelweiss LLC [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 0 0 0
Earnings (Loss)                 151 0 0
Our share of earnings (loss)                 137 0 0
MRECV Juniper Ridge LLC [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 0 0 0
Earnings (Loss)                 106 0 0
Our share of earnings (loss)                 0 0 0
Miramonte Boulder Pass, LLC [Member] [Domain]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 0 0 0
Earnings (Loss)                 (250) 0 0
Our share of earnings (loss)                 (125) 0 0
PSW Communities [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 29,986 0 0
Earnings (Loss)                 2,688 (86) 0
Our share of earnings (loss)                 1,169 (76) 0
Temco [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 9,485 2,155 630
Earnings (Loss)                 2,358 494 96
Our share of earnings (loss)                 1,179 247 48
Other Ventures [Member]                      
Schedule of Equity Method Investments [Line Items]                      
Revenues                 36,237 1,792 5,994
Earnings (Loss)                 33,303 4,835 176
Our share of earnings (loss)                 $ 1,278 $ 260 $ 33
[1] Non-cash impairment charges for unproved leasehold interests and proved oil and gas properties included in our quarterly financial results are as follows: First Quarter Second Quarter Third Quarter FourthQuarter (In thousands)2015$7 $45,938 $81,240 $37,6462014755 584 735 30,591
[2] Includes unamortized deferred gains on real estate contributed by us to ventures. We recognize deferred gains as income as real estate is sold to third parties. Deferred gains of $1,496,000 are reflected as a reduction to our investment in unconsolidated ventures at year-end 2015.
[3] In 2014, we acquired full ownership in the Eleven venture for $21,500,000. The acquisition-date fair value was $55,275,000, including debt of $23,936,000. Our investment in the Eleven venture prior to acquiring our partner’s interest was $2,229,000.
[4] Includes unrecognized basis difference of $34,000 which is reflected as a reduction of our investment in unconsolidated ventures at year-end 2015. This difference between estimated fair value of the equity investment and our capital account within the respective ventures at closing will be accreted as income or expense over the life of the investment and included in our share of earnings (loss) from the respective ventures.
v3.3.1.900
Investment In Unconsolidated Ventures - Summarized Income Statement Information (Footnotes) (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]    
Reduction in investment $ 34  
242, LLC [Member]    
Schedule of Equity Method Investments [Line Items]    
Reduction in investment $ 1,496  
Other Ventures [Member] | Minimum [Member]    
Schedule of Equity Method Investments [Line Items]    
Equity Method Investment, Ownership Percentage 40.00%  
Other Ventures [Member] | Maximum [Member]    
Schedule of Equity Method Investments [Line Items]    
Equity Method Investment, Ownership Percentage 75.00%  
Equity Method Investments [Member]    
Schedule of Equity Method Investments [Line Items]    
Long-term Debt, Current Maturities $ 39,590 $ 65,795
Equity Method Investments [Member] | Non-recourse Debt [Member]    
Schedule of Equity Method Investments [Line Items]    
Long-term Debt, Current Maturities $ 6,798 $ 42,566
v3.3.1.900
Receivables - Receivables (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Receivables, gross $ 23,893 $ 24,847
Oil and gas joint interest billing receivables 867 5,738
Allowance for bad debts (237) (258)
Receivables, net 23,656 24,589
Loan secured by real estate [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Receivables, gross 0 3,574
Other loans secured by real estate [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Receivables, gross $ 2,130 $ 1,737
Average Interest Rates 11.31% 4.41%
Oil and gas revenue accrual receivable [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Receivables, gross $ 3,745 $ 7,293
Other receivables and accrued interest [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Receivables, gross $ 2,448 $ 6,505
v3.3.1.900
Receivables - Additional Information (Detail)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
USD ($)
a
Dec. 31, 2014
USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Accounts and Notes Receivables $ 23,893 $ 24,847
Due period of notes receivable as secured by deed of trust 3 years  
Funds held by qualified intermediary [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Accounts and Notes Receivables $ 14,703 0
Area of Land | a 6,915  
Loan secured by real estate [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Accounts and Notes Receivables $ 0 3,574
Principal amount of loan received 4,394  
Interest amount of loan received 49  
Other loans secured by real estate [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Accounts and Notes Receivables $ 2,130 $ 1,737
v3.3.1.900
Receivables - Estimated Accretable Yield (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Receivables [Abstract]    
Beginning of period $ 839 $ 8,908
Change in accretable yield due to change in timing of estimated cash flows 30 (166)
Interest income recognized (869) (7,903)
End of period $ 0 $ 839
v3.3.1.900
Debt - Schedule of Debt (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Line of Credit Facility [Line Items]    
Debt $ 389,782 $ 432,744
6% Tangible Equity Units [Member]    
Line of Credit Facility [Line Items]    
Debt 8,768 17,154
Term Loan Facility [Member] | Senior Secured Credit Facility [Member]    
Line of Credit Facility [Line Items]    
Debt   200,000
Senior Notes [Member]    
Line of Credit Facility [Line Items]    
Debt 230,560 250,000
Convertible Debt [Member]    
Line of Credit Facility [Line Items]    
Debt 106,762 103,194
Secured Promissory Notes [Member]    
Line of Credit Facility [Line Items]    
Debt 15,400 15,400
Other Indebtedness [Member]    
Line of Credit Facility [Line Items]    
Debt $ 28,292 $ 46,996
v3.3.1.900
Debt - Debt (Detail)
 12 Months Ended
Feb. 26, 2013
Dec. 31, 2015
Dec. 31, 2014
Convertible Debt [Member]      
Line of Credit Facility [Line Items]      
Average interest rate   3.75% 3.75%
Debt Instrument, Maturity Date Mar. 01, 2020    
6% Tangible Equity Units [Member]      
Line of Credit Facility [Line Items]      
Average interest rate   6.00% 6.00%
Secured Promissory Notes [Member]      
Line of Credit Facility [Line Items]      
Average interest rate   3.42% 3.17%
Other Indebtedness [Member]      
Line of Credit Facility [Line Items]      
Variable and fixed interest rates ranging, minimum   2.19%  
Variable and fixed interest rates ranging, maximum   5.50%  
Senior Notes [Member]      
Line of Credit Facility [Line Items]      
Debt Instrument, Maturity Date Jun. 01, 2022    
Revolving Credit Facility [Member]      
Line of Credit Facility [Line Items]      
Line of Credit Facility, Expiration Date   May 15, 2017  
Senior Secured Credit Facility [Member] | Revolving Credit Facility [Member]      
Line of Credit Facility [Line Items]      
Average interest rate   8.50% 8.50%
Second Amended Senior Secured Credit Facility [Member] [Member] | Term Loan Facility [Member]      
Line of Credit Facility [Line Items]      
Line of Credit Facility, Expiration Date   Sep. 14, 2017  
Second Amended Senior Secured Credit Facility [Member] [Member] | Revolving Line of Credit [Member]      
Line of Credit Facility [Line Items]      
Debt Instrument, Maturity Date   Sep. 14, 2015  
6% Tangible Equity Units [Member] | Senior Notes [Member]      
Line of Credit Facility [Line Items]      
Line of Credit Facility, Expiration Date   Dec. 15, 2016  
v3.3.1.900
Debt - Additional Information (Detail)
 12 Months Ended
Nov. 27, 2013
USD ($)
shares
Unit
$ / shares
$ / Unit
Feb. 26, 2013
USD ($)
Dec. 31, 2015
USD ($)
Property
Room
$ / shares
Dec. 31, 2014
USD ($)
Property
$ / shares
Dec. 31, 2013
USD ($)
Apr. 01, 2016
Mar. 31, 2016
Sep. 30, 2015
Line of Credit Facility [Line Items]                
NetIncomePercentageRequiredforNetWorthCompliance     75.00%          
MinimumNetWorthPercentageRequiredForCompliance     85.00%          
Common stock, par value | $ / shares     $ 1.00 $ 1.00        
Debt     $ 389,782,000 $ 432,744,000        
Repayments of Long-term Debt     58,220,000 225,481,000 $ 106,076,000      
Deferred Finance Costs, Net     11,034,000 15,168,000        
Amortization of deferred financing fees     4,002,000 $ 3,845,000 $ 3,050,000      
Debt Maturities 2016     27,973,000          
Debt Maturities 2017     551,000          
Debt Maturities 2018     23,936,000          
Debt Maturities 2019     0          
Debt Maturities 2020     106,762,000          
Debt Maturities thereafter     $ 230,560,000          
Austin [Member]                
Line of Credit Facility [Line Items]                
Guest room hotel | Room     413          
Multi Family Property [Member] | Austin, Texas [Member]                
Line of Credit Facility [Line Items]                
Number Of Units Of Multifamily Project | Property     257 257        
Carrying value       $ 53,917,000        
Multi Family Development Properties [Member] | Texas [Member]                
Line of Credit Facility [Line Items]                
Carrying value     $ 51,035,000          
6% Tangible Equity Units [Member]                
Line of Credit Facility [Line Items]                
Debt Instrument, Face Amount $ 150,000,000              
Units issued | Unit 6,000,000              
Exercise price of unit | $ / Unit 25.00              
Common stock, par value | $ / shares $ 1.00              
Interest rate percentage 6.00%              
Debt     8,768,000 17,154,000        
Revolving Line of Credit [Member] | Sublimit For Letters Of Credit [Member]                
Line of Credit Facility [Line Items]                
Sublimit for letters of credit under line of credit facility     100,000,000          
Term Loan Facility [Member] | Senior Secured Credit Facility [Member]                
Line of Credit Facility [Line Items]                
Debt       200,000,000        
Letter of Credit [Member]                
Line of Credit Facility [Line Items]                
Sublimit for letters of credit outstanding     15,899,000          
Convertible Debt [Member]                
Line of Credit Facility [Line Items]                
Debt Instrument, Face Amount   $ 125,000,000            
Debt Instrument, Maturity Date   Mar. 01, 2020            
Interest rate percentage   3.75%            
Initial conversion rate   40.8351            
Principal amount of initial conversion rate   $ 1,000            
Unamortized debt discount     18,238,000          
Debt     $ 106,762,000 103,194,000        
Senior Notes [Member]                
Line of Credit Facility [Line Items]                
Debt Instrument, Maturity Date   Jun. 01, 2022            
Interest rate percentage     8.50%          
Debt     $ 230,560,000 250,000,000        
Notes Reduction     $ 19,440,000          
Debt Instrument, Redemption Price, Percentage     97.00%          
Gains (Losses) on Extinguishment of Debt, before Write off of Deferred Debt Issuance Cost     $ 589,000          
Write off of Deferred Debt Issuance Cost     $ 506,000          
Senior Notes [Member] | 6% Tangible Equity Units [Member]                
Line of Credit Facility [Line Items]                
Line of Credit Facility, Expiration Date     Dec. 15, 2016          
Face amount per unit, debt | $ / Unit 4.2522              
Interest rate percentage 4.50%              
Secured Promissory Notes [Member]                
Line of Credit Facility [Line Items]                
Debt     $ 15,400,000 15,400,000        
Secured Promissory Notes [Member] | Austin [Member]                
Line of Credit Facility [Line Items]                
Carrying value of multifamily project to secure non recourse loan     33,621,000          
Other Indebtedness [Member]                
Line of Credit Facility [Line Items]                
Debt     28,292,000 46,996,000        
Other Indebtedness [Member] | Multi Family Property [Member] | Austin, Texas [Member]                
Line of Credit Facility [Line Items]                
Debt     23,936,000          
Revolving Credit Facility [Member]                
Line of Credit Facility [Line Items]                
Minimum liquidity required     $ 125,000,000          
Minimum effective leverage ratio exceeded     40.00%          
Debt Instrument, Stockholders Distribution Covenant, Interest Coverage Ratio     3.0          
Maximum borrowing capacity under term Loan facility     $ 300,000,000          
Line of Credit Facility, Expiration Date     May 15, 2017          
Net unused borrowing capacity     $ 284,101,000          
Percentage Of Spread On Federal Funds Effective Rate     0.50%          
Minimum Net Worth Required for Compliance     $ 379,044,000          
Debt Instrument, Covenant, Interest Coverage Ratio     2.25         2.50
Payments of Capital Distribution     $ 50,000,000          
Debt Instrument, Distribution Funding, Percentage From Sales of Properties and Non-core Assets     65.00%          
Minimum [Member] | 6% Tangible Equity Units [Member]                
Line of Credit Facility [Line Items]                
Units issued | shares 6,547,800              
Maximum [Member] | 6% Tangible Equity Units [Member]                
Line of Credit Facility [Line Items]                
Units issued | shares 7,857,000              
Over-Allotment Option [Member] | 6% Tangible Equity Units [Member]                
Line of Credit Facility [Line Items]                
Units issued | Unit 600,000              
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member]                
Line of Credit Facility [Line Items]                
Debt Instrument, Basis Spread on Variable Rate     4.00%          
Base Rate [Member] | Revolving Credit Facility [Member]                
Line of Credit Facility [Line Items]                
Percentage Of Variable Spread On Base Rate     3.00%          
Thirty Day LIBOR Rate [Member] | Revolving Credit Facility [Member]                
Line of Credit Facility [Line Items]                
Debt Instrument, Basis Spread on Variable Rate     1.00%          
Midtown [Member]                
Line of Credit Facility [Line Items]                
Number Of Units Of Multifamily Project | Property     354          
Proceeds from sale of multifamily property     $ 18,473,000          
Carrying value     0 [1] $ 33,293,000        
Repayments of Long-term Debt     $ 24,166,000          
Scenario, Forecast [Member] | Revolving Credit Facility [Member]                
Line of Credit Facility [Line Items]                
Debt Instrument, Covenant, Interest Coverage Ratio           2.50 2.25  
[1] Sold in 2015.
v3.3.1.900
Fair Value - Additional Information (Detail) - USD ($)
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]      
Impairment of Oil and Gas Properties $ 107,140,000    
Asset impairments 108,184,000 $ 15,934,000 $ 1,790,000
Real Estate [Member]      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]      
Asset impairments $ 1,044,000 $ 399,000  
v3.3.1.900
Fair Value - Carrying Value of Assets (Detail) - Non-recurring [Member] - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
ProvedOilGasProperty [Member]    
Non-Financial Assets and Liabilities:    
Real estate $ 39,000 $ 3,655
ProvedOilGasProperty [Member] | Level 1 [Member]    
Non-Financial Assets and Liabilities:    
Real estate 0 0
ProvedOilGasProperty [Member] | Level 2 [Member]    
Non-Financial Assets and Liabilities:    
Real estate 0 0
ProvedOilGasProperty [Member] | Level 3 [Member]    
Non-Financial Assets and Liabilities:    
Real estate 39,000 3,655
Oil and Gas Properties [Member]    
Non-Financial Assets and Liabilities:    
Real estate 18,219 0
Oil and Gas Properties [Member] | Level 1 [Member]    
Non-Financial Assets and Liabilities:    
Real estate 0 0
Oil and Gas Properties [Member] | Level 2 [Member]    
Non-Financial Assets and Liabilities:    
Real estate 0 0
Oil and Gas Properties [Member] | Level 3 [Member]    
Non-Financial Assets and Liabilities:    
Real estate 18,219 0
Real Estate [Member]    
Non-Financial Assets and Liabilities:    
Real estate 641 970
Real Estate [Member] | Level 1 [Member]    
Non-Financial Assets and Liabilities:    
Real estate 0 0
Real Estate [Member] | Level 2 [Member]    
Non-Financial Assets and Liabilities:    
Real estate 0 0
Real Estate [Member] | Level 3 [Member]    
Non-Financial Assets and Liabilities:    
Real estate $ 641 $ 970
v3.3.1.900
Fair Value - Information About our Fixed Rate Financial instruments not Measured at Fair Value (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Debt $ 389,782 $ 432,744
Senior Notes [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Debt $ 230,560 250,000
Interest rate percentage 8.50%  
Reported Value Measurement [Member] | Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Loan Secured by Real Estate Fair Value $ 0 3,574
Fixed rate debt, fair value (346,090) (370,348)
Estimate of Fair Value Measurement [Member] | Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Loan Secured by Real Estate Fair Value 0 4,859
Fixed rate debt, fair value $ (321,653) $ (359,131)
v3.3.1.900
Capital Stock - (Detail) - USD ($)
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Nov. 27, 2013
Feb. 26, 2013
Class of Stock [Line Items]        
Number of shares repurchased   1,491,187    
Value of share repurchased   $ 24,595,000    
Common Stock Repurchased Since Announcement Of Strategic Initiative 3,493,332      
Value Of Common Stock Repurchased Since Announcement Of Strategic Initiative $ 54,159,000      
Maximum percentage of shares repurchased under strategic initiative 20.00%      
Maximum number of shares repurchased under strategic initiative 7,000,000      
Stock Options [Member]        
Class of Stock [Line Items]        
Options to purchase shares of common stock 1,687,000      
Weighted average exercise price $ 20.83      
Weighted average remaining contractual term 4 years      
Aggregate intrinsic value $ 156,000 $ 643,000    
Former Affiliated Entity [Member] | Stock Options [Member]        
Class of Stock [Line Items]        
Options to purchase shares of common stock 500,798      
Weighted average exercise price $ 28.62      
Weighted average remaining contractual term 1 year      
Aggregate intrinsic value $ 0      
6% Tangible Equity Units [Member]        
Class of Stock [Line Items]        
Interest rate percentage     6.00%  
Convertible Debt [Member]        
Class of Stock [Line Items]        
Interest rate percentage       3.75%
Preferred Stock [Member]        
Class of Stock [Line Items]        
Expiry date of rights Dec. 11, 2017      
v3.3.1.900
Net Income (Loss) per Share - Earnings Attributable to Common Shareholders and Weighted Average Common Shares Outstanding (Detail) - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Numerator:      
Consolidated net income (loss) $ (212,371) $ 17,088 $ 35,061
Less: Net (income) attributable to noncontrolling interest (676) (505) (5,740)
Income (loss) available for diluted earnings per share (213,047) 16,583 29,321
Less: Undistributed net income allocated to participating securities 0 (3,018) (585)
Income (loss) available to common shareholders for basic earnings per share $ (213,047) $ 13,565 $ 28,736
Weighted average common shares outstanding - basic 34,266 35,317 35,365
Weighted average common shares upon conversion of participating securities 0 7,857 835
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements 0 422 613
Weighted average common shares outstanding - diluted 34,266 43,596 36,813
Anti-dilutive awards excluded from diluted weighted average shares outstanding 10,864 2,238 1,803
v3.3.1.900
Net Income (Loss) per Share - Additional Information (Details)
Nov. 27, 2013
shares
Unit
Dec. 31, 2015
$ / shares
6% Tangible Equity Units [Member]    
Debt Instrument [Line Items]    
Stated interest rate on tangible equity units 6.00%  
Units issued | Unit 6,000,000  
Convertible Debt [Member]    
Debt Instrument [Line Items]    
Exercise price of unit | $ / shares   $ 24.49
Minimum [Member] | 6% Tangible Equity Units [Member]    
Debt Instrument [Line Items]    
Units issued 6,547,800  
Maximum [Member] | 6% Tangible Equity Units [Member]    
Debt Instrument [Line Items]    
Units issued 7,857,000  
v3.3.1.900
Income Taxes - Income Tax Expense (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Current tax provision:      
U.S. Federal $ 8,579 $ (5,444) $ (6,004)
State and other 47 (1,569) (2,066)
Total 8,626 (7,013) (8,070)
Deferred tax provision:      
U.S. Federal (38,366) (2,772) 1,148
State and other (2,895) 1,128 (286)
Total (41,261) (1,644) 862
Income tax expense $ (32,635) $ (8,657) $ (7,208)
v3.3.1.900
Income Taxes - Reconciliation of Federal Statutory Rate to Effective Income Tax Rate on Continuing Operations (Detail)
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Income Tax Disclosure [Abstract]      
Federal statutory rate (benefit) (35.00%) 35.00% 35.00%
State, net of federal benefit (1.00%) 1.00% 4.00%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount 54.00% 0.00% 0.00%
Recognition of previously unrecognized tax benefits 0.00% 0.00% (15.00%)
Noncontrolling interests 0.00% 0.00% (5.00%)
Effective Income Tax Rate Reconciliation, Disposition of Asset, Percent 0.00% 1.00% 0.00%
Charitable contributions 0.00% (1.00%) 0.00%
Oil and gas percentage depletion 0.00% (2.00%) (2.00%)
Effective tax rate 18.00% 34.00% 17.00%
v3.3.1.900
Income Taxes - Additional Information (Detail) - USD ($)
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Operating Loss Carryforwards [Line Items]      
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount $ 0.54    
Recognition of previously unrecognized tax benefits (0.00%) (0.00%) 15.00%
Oil and gas percentage depletion carryforwards $ 9,800,000    
Tax benefits not recognized for book purposes     $ 6,326,000
Recognized interest accrued related to unrecognized tax benefits 0 $ 0 $ 75,000
Accrued interest 0    
Credo [Member]      
Operating Loss Carryforwards [Line Items]      
Oil and gas percentage depletion carryforwards 9,200,000    
Domestic Tax Authority [Member]      
Operating Loss Carryforwards [Line Items]      
Operating loss carry forwards $ 37,500,000    
Expiration date of operating loss carry forwards Dec. 31, 2035    
Domestic Tax Authority [Member] | Credo [Member]      
Operating Loss Carryforwards [Line Items]      
Operating loss carry forwards $ 7,500,000    
State and Local Jurisdiction [Member]      
Operating Loss Carryforwards [Line Items]      
Operating loss carry forwards 43,900,000    
State and Local Jurisdiction [Member] | Credo [Member]      
Operating Loss Carryforwards [Line Items]      
Operating loss carry forwards $ 2,400,000    
Minimum [Member] | State and Local Jurisdiction [Member]      
Operating Loss Carryforwards [Line Items]      
Expiration date of operating loss carry forwards Dec. 31, 2016    
Maximum [Member] | State and Local Jurisdiction [Member]      
Operating Loss Carryforwards [Line Items]      
Expiration date of operating loss carry forwards Dec. 31, 2035    
v3.3.1.900
Income Taxes - Significant Components of Deferred Taxes (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Deferred Tax Assets:    
Real estate $ 69,594 $ 79,244
Employee benefits 15,752 17,352
Net operating loss carryforwards 13,827 3,012
Deferred Tax Assets, Oil And Gas Properties 5,510 0
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax 3,620 0
Income producing properties 0 364
Oil and gas percentage depletion carryforwards 3,616 3,471
Accruals not deductible until paid 911 1,111
Deferred Tax Assets, Other 139 0
Gross deferred tax assets 112,969 104,554
Valuation allowance (97,068) (384)
Deferred tax asset net of valuation allowance 15,901 104,170
Deferred Tax Liabilities:    
Oil and gas properties 0 (49,905)
Undeveloped land (7,588) (4,937)
Convertible debt (6,516) (7,816)
Income producing properties (2,257) 0
Timber (577) (888)
Gross deferred tax liabilities 16,938 63,546
Deferred Tax Liabilities, Net (1,037) 0
Deferred Tax Assets, Net $ 0 $ 40,624
v3.3.1.900
Income Taxes - Reconciliation of Beginning and Ending Amount of Tax Benefits Not Recognized for Book Purposes (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Income Tax Disclosure [Abstract]      
Balance at beginning of year $ 0 $ 0 $ 5,831
Reductions for tax positions of prior years 0 0 0
Reductions due to lapse of statute of limitations 0 0 (5,831)
Balance at end of year $ 0 $ 0 $ 0
v3.3.1.900
Litigation and Environmental Contingencies - Additional Information (Detail)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
USD ($)
a
Dec. 31, 2014
USD ($)
Dec. 31, 2013
USD ($)
Commitments and Contingencies Disclosure [Abstract]      
Area for which certificate of completion is required | a 288    
Portion of site for which certificate not received | a 80    
Accrual for Environmental Loss Contingencies, Increase (Decrease) for Revision in Estimates $ 689    
Cost to complete remediation activities 682    
Asset Retirement Obligation $ 1,758 $ 1,807 $ 1,483
v3.3.1.900
Commitments and Other Contingencies (Detail)
ft² in Thousands, a in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2015
USD ($)
ft²
Dec. 31, 2015
USD ($)
a
ft²
Dec. 31, 2014
USD ($)
Dec. 31, 2013
USD ($)
Dec. 31, 2008
ft²
Operating Leased Assets [Line Items]          
Restructuring Reserve $ (1,049,000) $ (1,049,000) $ (2,367,000)    
operating lease future payments, 2015 2,696,000 2,696,000      
operating lease future payments, 2016 2,738,000 2,738,000      
operating lease future payments, 2016 1,706,000 1,706,000      
operating lease future payments, 2018 170,000 170,000      
operating lease future payments, 2019 174,000 174,000      
operating lease future payments, thereafter 59,000 59,000      
Restructuring Charges   (3,797,000)      
Payments for Restructuring   5,115,000      
Office Facilities And Other Equipment [Member]          
Operating Leased Assets [Line Items]          
Lease expense   $ 3,872,000 2,617,000 $ 2,374,000  
Ground Water Lease [Member]          
Operating Leased Assets [Line Items]          
Remaining years of timber lease   2 years      
Timber land area taken on lease | a   20      
Remaining contractual obligation 1,009,000 $ 1,009,000      
Corporate Headquarters [Member]          
Operating Leased Assets [Line Items]          
Net Rentable Area | ft²         32
Remaining contractual obligation 4,212,000 4,212,000      
Other Office Locations [Member]          
Operating Leased Assets [Line Items]          
Remaining contractual obligation $ 2,269,000 $ 2,269,000      
Other Office Locations [Member] | Texas [Member]          
Operating Leased Assets [Line Items]          
Net Rentable Area | ft² 21 21      
Facility Closing [Member]          
Operating Leased Assets [Line Items]          
Restructuring Reserve $ 0 $ 0 0    
Restructuring Charges   (1,750,000)      
Payments for Restructuring   1,750,000      
Special Termination Benefits [Member] | Oil and Gas [Member]          
Operating Leased Assets [Line Items]          
Restructuring Reserve (1,049,000) (1,049,000) $ (2,367,000)    
Restructuring Charges   (2,047,000)      
Payments for Restructuring   3,365,000      
Other Restructuring [Member] | Leasehold Improvements [Member]          
Operating Leased Assets [Line Items]          
Restructuring Charges   (391,000)      
Deferred Lease Revenue [Member]          
Operating Leased Assets [Line Items]          
Restructuring Charges   364,000      
General and Administrative Expense [Member] | One-time Termination Benefits [Member]          
Operating Leased Assets [Line Items]          
Restructuring Charges   $ (3,314,000)      
General and Administrative Expense [Member] | Special Termination Benefits [Member]          
Operating Leased Assets [Line Items]          
Payments for Restructuring $ 2,732,000        
v3.3.1.900
Segment Information - Additional Information (Detail)
 12 Months Ended
Dec. 31, 2015
Segment
Customer
Dec. 31, 2014
Customer
Segment Reporting [Abstract]    
Number of business segments | Segment 3  
Concentration Risk, Percentage 10.00%  
Number of customer who contributed more than 10 percent of revenue | Customer 0 0
v3.3.1.900
Segment Information - Segment Revenues and Earnings (Detail) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
 [1]
Jun. 30, 2015
 [1]
Mar. 31, 2015
 [1]
Dec. 31, 2014
Sep. 30, 2014
 [1]
Jun. 30, 2014
 [1]
Mar. 31, 2014
 [1]
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Segment Reporting Information [Line Items]                      
Revenues $ 114,018 [1] $ 43,168 $ 57,430 $ 47,805 $ 80,316 [1] $ 58,840 $ 83,013 $ 84,605 $ 262,421 $ 306,774 $ 331,045
Depreciation, depletion and amortization                 45,085 41,715 29,980
Equity in earnings of unconsolidated ventures 4,470 [1] $ 2,909 $ 5,584 $ 3,045 4,720 [1] $ 2,016 $ 958 $ 991 16,008 8,685 8,737
Income (loss) before taxes                 (180,412) 25,240 36,529
Total assets 980,513       1,258,199       980,513 1,258,199 1,172,152
Investment in unconsolidated ventures 82,453       65,005       82,453 65,005 41,147
Capital expenditures [2]                 64,407 138,798 107,897
Operating Segments [Member] | Real Estate [Member]                      
Segment Reporting Information [Line Items]                      
Revenues                 202,830 213,112 248,011
Depreciation, depletion and amortization                 7,605 3,741 3,117
Equity in earnings of unconsolidated ventures                 15,582 8,068 8,089
Income (loss) before taxes                 67,678 96,906 68,454
Total assets 691,406       654,774       691,406 654,774 582,802
Investment in unconsolidated ventures 82,453       65,005       82,453 65,005 41,147
Capital expenditures [2]                 13,644 28,980 7,265
Operating Segments [Member] | Oil and Gas [Member]                      
Segment Reporting Information [Line Items]                      
Revenues                 52,939 84,300 72,313
Depreciation, depletion and amortization                 28,774 29,442 19,552
Equity in earnings of unconsolidated ventures                 275 586 592
Income (loss) before taxes                 (184,396) (22,686) 18,859
Total assets 144,436       342,703       144,436 342,703 312,553
Investment in unconsolidated ventures 0       0       0 0 0
Capital expenditures [2]                 49,776 103,385 97,696
Operating Segments [Member] | Other Natural Resources [Member]                      
Segment Reporting Information [Line Items]                      
Revenues                 6,652 9,362 10,721
Depreciation, depletion and amortization                 540 497 651
Equity in earnings of unconsolidated ventures                 151 31 56
Income (loss) before taxes                 (608) 5,499 6,507
Total assets 19,106       22,531       19,106 22,531 23,478
Investment in unconsolidated ventures 0       0       0 0 0
Capital expenditures [2]                 745 5,817 2,720
Items Not Allocated To Segments [Member]                      
Segment Reporting Information [Line Items]                      
Revenues                 0 0 0
Depreciation, depletion and amortization                 8,166 8,035 6,660
Equity in earnings of unconsolidated ventures                 0 0 0
Income (loss) before taxes [3]                 (63,086) (54,479) (57,291)
Total assets 125,565       238,191       125,565 238,191 253,319
Investment in unconsolidated ventures $ 0       $ 0       0 0 0
Capital expenditures [2]                 $ 242 $ 616 $ 216
[1] Non-cash impairment charges for unproved leasehold interests and proved oil and gas properties included in our quarterly financial results are as follows: First Quarter Second Quarter Third Quarter FourthQuarter (In thousands)2015$7 $45,938 $81,240 $37,6462014755 584 735 30,591
[2] Consists of expenditures for oil and gas properties and equipment, commercial and income producing properties, property, plant and equipment and reforestation of timber.
[3] Items not allocated to segments consist of: For the Year 2015 2014 2013 (In thousands)General and administrative expense$(24,802) $(21,229) $(20,597)Share-based and long-term incentive compensation expense(4,474) (3,417) (16,809)Interest expense(34,066) (30,286) (20,004)Other corporate non-operating income256 453 119 $(63,086) $(54,479) $(57,291)
v3.3.1.900
Segment Information - Items Not Allocated to Segments (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Segment Reporting Information [Line Items]      
Income (loss) before taxes $ (180,412) $ 25,240 $ 36,529
Items Not Allocated To Segments [Member]      
Segment Reporting Information [Line Items]      
Income (loss) before taxes [1] (63,086) (54,479) (57,291)
Items Not Allocated To Segments [Member] | General and Administrative Expense [Member]      
Segment Reporting Information [Line Items]      
Income (loss) before taxes (24,802) (21,229) (20,597)
Items Not Allocated To Segments [Member] | Share-based compensation expense [Member]      
Segment Reporting Information [Line Items]      
Income (loss) before taxes (4,474) (3,417) (16,809)
Items Not Allocated To Segments [Member] | Interest expense [Member]      
Segment Reporting Information [Line Items]      
Income (loss) before taxes (34,066) (30,286) (20,004)
Items Not Allocated To Segments [Member] | Other corporate non-operating income [Member]      
Segment Reporting Information [Line Items]      
Income (loss) before taxes $ 256 $ 453 $ 119
[1] Items not allocated to segments consist of: For the Year 2015 2014 2013 (In thousands)General and administrative expense$(24,802) $(21,229) $(20,597)Share-based and long-term incentive compensation expense(4,474) (3,417) (16,809)Interest expense(34,066) (30,286) (20,004)Other corporate non-operating income256 453 119 $(63,086) $(54,479) $(57,291)
v3.3.1.900
Variable Interest Entities - Additional Information (Detail)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
USD ($)
Entity
Dec. 31, 2014
USD ($)
Dec. 31, 2013
USD ($)
Variable Interest Entity [Line Items]      
Payments to Acquire Additional Interest in Subsidiaries $ 0 $ 7,971 $ 0
Deferred Tax Assets, Net $ 0 40,624  
Variable Interest Entity, Not Primary Beneficiary [Member]      
Variable Interest Entity [Line Items]      
Count of VIEs | Entity 2    
Variable Interest Entity, Non consolidated, Carrying amount, Assets $ 62,187    
Variable Interest Entity, Nonconsolidated, Carrying Amount, Liabilities 55,989    
Variable Interest Entity, Financial or Other Support, Amount 148    
Maximum Exposure to loss related to VIEs 3,780    
Investment in VIEs 5,322    
Noncontrolling Interest [Member]      
Variable Interest Entity [Line Items]      
Deferred Tax Assets, Net   $ 1,729  
Borrowings [Member] | Variable Interest Entity, Not Primary Beneficiary [Member]      
Variable Interest Entity [Line Items]      
Variable Interest Entity, Nonconsolidated, Carrying Amount, Liabilities $ 2,269    
v3.3.1.900
Share Based Compensation - Components of Share-Based Compensation Expense (Income) (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation $ 4,246 $ 3,417 $ 16,809
Deferred Compensation Arrangement with Individual, Compensation Expense 228 0 0
Share-Based and Long-Term Incentive Compensation 4,474 3,417 16,809
Stock Options [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation 2,355 1,984 4,216
Restricted Stock [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation (8) (25) 538
Equity-settled awards [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation 5,026 5,168 4,281
Cash Settled Awards [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation $ (3,127) $ (3,710) $ 7,774
v3.3.1.900
Share Based Compensation - Share Based Compensation Expense Included in Operating Expense (Income) (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-Based and Long-Term Incentive Compensation $ 4,474 $ 3,417 $ 16,809
General and Administrative Expense [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-Based and Long-Term Incentive Compensation 2,451 1,001 7,779
Other Operating Expenses [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-Based and Long-Term Incentive Compensation $ 2,023 $ 2,416 $ 9,030
v3.3.1.900
Share Based Compensation - Additional Information (Detail) - USD ($)
 3 Months Ended 12 Months Ended
Sep. 30, 2015
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Share-based compensation   $ 4,246,000 $ 3,417,000 $ 16,809,000
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost   517,000 $ 760,000 590,000
Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options   $ 5,109,000    
Weighted average period over which amount will be recognized   2 years    
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures   288,089 215,561  
Vesting of restricted stock awards and exercises of stock options, shares withheld   51,521 55,238  
Payroll taxes on restricted stock and stock options   $ 762,000 $ 1,043,000 1,137,000
Stock price of non-vested cash-settled awards   $ 10.94    
Financial Instruments Subject to Mandatory Redemption, Settlement Terms, Share Value, Amount, Noncurrent $ 17.50      
Deferred Compensation Arrangement with Individual, Cash Award Granted, Amount   $ 587,000    
Deferred Compensation Cash-based Arrangements, Liability, Current and Noncurrent   225,000    
Board of Director Fees [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Share-based compensation   1,203,000 906,000 876,000
Cash Settled Awards [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Share-based compensation   (3,127,000) (3,710,000) 7,774,000
Fair value of vested cash-settled awards   3,757,000 $ 9,560,000  
Aggregate current value of non-vested cash-settled awards   $ 1,286,000    
Cash Settled Awards [Member] | Minimum [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Period over or after performance stock unit vest   3 years    
Cash Settled Awards [Member] | Maximum [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Period over or after performance stock unit vest   4 years    
Restricted Stock Units (RSUs) [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Period over or after performance stock unit vest   3 years    
Restricted Stock Units (RSUs) [Member] | Minimum [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Period over or after performance stock unit vest   3 years    
Restricted Stock Units (RSUs) [Member] | Maximum [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Period over or after performance stock unit vest   4 years    
Stock Appreciation Rights (SARs) [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Nonvested, weighted average grant date fair value   $ 12.97 $ 12.54  
Aggregate current value of non-vested cash-settled restricted stock units   487,000 458,000  
Fair value of awards settled in cash   $ 206,000 $ 1,181,000 3,458,000
Period over or after performance stock unit vest   4 years    
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period   10 years    
Granted, Equivalent Units   90,000    
Market-leveraged stock units [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Period over or after performance stock unit vest   3 years    
Granted, Equivalent Units   234,000    
Number of shares to be issued if stock price increases by fifty percent   351,000    
Numbers of shares to be issued if stock price decreases by fifty percent   117,000    
Equity-settled awards [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Share-based compensation   $ 5,026,000 $ 5,168,000 4,281,000
Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options   $ 3,258,000    
Weighted average period over which amount will be recognized   2 years    
Nonvested, weighted average grant date fair value   $ 18.25 $ 19.24  
Aggregate current value of non-vested cash-settled restricted stock units   631,000 710,000  
Fair value of vested cash-settled awards   $ 4,451,000,000 $ 3,119,000,000 8,000,000
Granted, Equivalent Units   395,000    
Minimum increases in stock price   50.00%    
Percentage of decrease in stock price   50.00%    
Restricted Stock [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Share-based compensation   $ (8,000) $ (25,000) 538,000
Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options   $ 14,000    
Weighted average period over which amount will be recognized   1 year    
Minimum Percent Annualized Return on Assets Vesting for Stock Unit Awards   1.00%    
Nonvested, weighted average grant date fair value   $ 20.55 $ 17.56  
Aggregate current value of non-vested cash-settled restricted stock units   4,000 17,000  
Fair value of vested cash-settled awards   $ 88,000,000 $ 341,000,000 3,002,000,000
Period over or after performance stock unit vest   3 years    
Granted, Equivalent Units   0    
Stock Options [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Share-based compensation   $ 2,355,000 1,984,000 4,216,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value   0 21,000 1,355,000
Unrecognized share-based compensation expense related to non-vested equity-settled awards, restricted stock and stock options   $ 1,837,000    
Weighted average period over which amount will be recognized   2 years    
Period over or after performance stock unit vest 3 years 4 years    
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period 10 years 10 years    
Intrinsic value of options exercised   $ 0 $ 568,000 562,000
Options Outstanding   2,171,000 1,861,000  
Weighted average exercise price   $ 20.83    
Weighted Average Remaining Contractual Term   5 years 6 years  
Aggregate intrinsic value   $ 156,000 $ 643,000  
Cash Settled Restricted Stock Unit [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Minimum Percent Annualized Return on Assets Vesting for Stock Unit Awards   1.00%    
Nonvested, weighted average grant date fair value   $ 16.00 $ 18.49  
Aggregate current value of non-vested cash-settled restricted stock units   117,000 185,000  
Fair value of awards settled in cash   $ 2,469,000 $ 2,286,000 3,780,000
Granted, Equivalent Units   60,000    
Performance Stock Units Psu [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Period over or after performance stock unit vest   3 years    
Special Performance [Member] | Minimum [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Special Performance Stock Unit awards to be issued   0    
Pre Spin Stock Option Awards [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Period over or after performance stock unit vest   4 years    
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period   10 years    
Options Outstanding   44,000    
Weighted average exercise price   $ 28.89    
Weighted Average Remaining Contractual Term   1 year    
Former Affiliated Entity [Member] | Stock Options [Member]        
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Intrinsic value of options exercised   $ 24,000 $ 352,000 $ 1,382,000
Weighted average exercise price   $ 28.62    
Aggregate intrinsic value   $ 0    
v3.3.1.900
Share Based Compensation - Summarized Activity of Cash Settled Restricted Stock Unit Awards (Detail) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2014
Mar. 31, 2013
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Stock Appreciation Rights (SARs) [Member]          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Balance at beginning of year     458    
Granted, Equivalent Units     90    
Forfeited, Equivalent Units     (22)    
Balance at end of period     487 458  
Non-vested at beginning of year, Weighted Average Grant Date Fair Value     $ 12.54    
Forfeited, Weighted Average Grant Date Fair Value     15.00    
Non-vested at end of period, Weighted Average Grant Date Fair Value     $ 12.97 $ 12.54  
Employee Service Share-based Compensation, Cash Flow Effect, Cash Used to Settle Awards     $ 206 $ 1,181 $ 3,458
Cash Settled Restricted Stock Unit [Member]          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Balance at beginning of year     185    
Granted, Equivalent Units     60    
Vested, Equivalent Units     (117)    
Forfeited, Equivalent Units     (11)    
Balance at end of period     117 185  
Non-vested at beginning of year, Weighted Average Grant Date Fair Value     $ 18.49    
Granted, Weighted Average Grant Date Fair Value $ 18.96 $ 18.70 13.26    
Vested, Weighted Average Grant Date Fair Value     18.26    
Forfeited, Weighted Average Grant Date Fair Value     18.83    
Non-vested at end of period, Weighted Average Grant Date Fair Value     $ 16.00 $ 18.49  
Employee Service Share-based Compensation, Cash Flow Effect, Cash Used to Settle Awards     $ 2,469 $ 2,286 $ 3,780
v3.3.1.900
Share Based Compensation - Summarized Activity of Cash-Settled Stock Appreciation Rights (Detail) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Stock Appreciation Rights (SARs) [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Fair value of awards settled in cash $ 206 $ 1,181 $ 3,458
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms 4 years 4 years  
Balance at beginning of year 458    
Granted, Rights Outstanding 90    
Exercised, Rights Outstanding (39)    
Forfeited, Rights Outstanding (22)    
Balance at end of period 487 458  
Exercisable at end of period, Rights Outstanding 414    
Non-vested at beginning of year, Weighted Average Grant Date Fair Value $ 12.54    
Granted, Weighted Average Exercise Price 14.08    
Exercised, Weighted Average Exercise Price 9.29    
Forfeited, Weighted Average Grant Date Fair Value 15.00    
Non-vested at end of period, Weighted Average Grant Date Fair Value 12.97 $ 12.54  
Exercisable at end of period, Weighted Average Exercise Price $ 12.77    
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Exercisable Weighted Average Remaining Contractual Term 3 years    
Aggregate Intrinsic Value $ 404 $ 1,732  
Exercisable at end of period, Aggregate Intrinsic Value 404    
Cash Settled Restricted Stock Unit [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Fair value of awards settled in cash $ 2,469 $ 2,286 $ 3,780
Balance at beginning of year 185    
Granted, Rights Outstanding 60    
Forfeited, Rights Outstanding (11)    
Balance at end of period 117 185  
Non-vested at beginning of year, Weighted Average Grant Date Fair Value $ 18.49    
Forfeited, Weighted Average Grant Date Fair Value 18.83    
Non-vested at end of period, Weighted Average Grant Date Fair Value $ 16.00 $ 18.49  
v3.3.1.900
Share Based Compensation - Equity-Settled Awards (Detail) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 3 Months Ended 12 Months Ended
Mar. 31, 2014
Mar. 31, 2013
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Equity-settled awards [Member]          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value     $ 12.99 $ 19.18 $ 20.21
Balance at beginning of year     710    
Granted, Equivalent Units     395    
Vested, Equivalent Units     (340)    
Forfeited, Equivalent Units     (134)    
Balance at end of period     631 710  
Non-vested at beginning of year, Weighted Average Grant Date Fair Value     $ 19.24    
Granted, Weighted Average Grant Date Fair Value     12.99    
Vested, Weighted Average Grant Date Fair Value     14.23    
Forfeited, Weighted Average Grant Date Fair Value     18.18    
Non-vested at end of period, Weighted Average Grant Date Fair Value     $ 18.25 $ 19.24  
Fair value of vested cash-settled awards     $ 4,451,000 $ 3,119,000 $ 8,000
Cash Settled Restricted Stock Unit [Member]          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Fair value of awards settled in cash     $ 2,469 $ 2,286 $ 3,780
Balance at beginning of year     185    
Granted, Equivalent Units     60    
Vested, Equivalent Units     (117)    
Forfeited, Equivalent Units     (11)    
Balance at end of period     117 185  
Non-vested at beginning of year, Weighted Average Grant Date Fair Value     $ 18.49    
Granted, Weighted Average Grant Date Fair Value $ 18.96 $ 18.70 13.26    
Vested, Weighted Average Grant Date Fair Value     18.26    
Forfeited, Weighted Average Grant Date Fair Value     18.83    
Non-vested at end of period, Weighted Average Grant Date Fair Value     $ 16.00 $ 18.49  
v3.3.1.900
Share Based Compensation - Summarized Activity of Restricted Stock Awards (Detail) - Restricted Stock [Member] - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Fair value of vested cash-settled awards $ 88,000 $ 341,000 $ 3,002,000
Balance at beginning of year 17    
Granted, Equivalent Units 0    
Vested, Equivalent Units (7)    
Forfeited, Equivalent Units (6)    
Balance at end of period 4 17  
Non-vested at beginning of year, Weighted Average Grant Date Fair Value $ 17.56    
Granted, Weighted Average Grant Date Fair Value 0.00    
Vested, Weighted Average Grant Date Fair Value 14.59    
Forfeited, Weighted Average Grant Date Fair Value 19.00    
Non-vested at end of period, Weighted Average Grant Date Fair Value $ 20.55 $ 17.56  
v3.3.1.900
Share Based Compensation - Summarized Activity of Stock Option Awards (Detail) - Stock Options [Member] - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Balance at beginning of year, Options Outstanding 1,861  
Granted, Options Outstanding 413  
Exercised, Options Outstanding 0  
Forfeited, Options Outstanding (103)  
Balance at end of period, Options Outstanding 2,171 1,861
Exercisable at end of period, Options Outstanding 1,687  
Balance at beginning of year, Weighted Average Exercise Price $ 20.74  
Granted, Weighted Average Exercise Price 13.86  
Exercised, Weighted Average Exercise Price 0.00  
Forfeited, Weighted Average Exercise Price 18.01  
Balance at end of period, Weighted Average Exercise Price 19.56 $ 20.74
Exercisable at end of period, Weighted Average Exercise Price $ 20.83  
Weighted Average Remaining Contractual Term 5 years 6 years
Exercisable at end of period, Weighted Average Remaining Contractual Term 4 years  
Aggregate intrinsic value $ 156 $ 643
Exercisable at end of period, Aggregate Intrinsic Value $ 156  
v3.3.1.900
Share Based Compensation - Fair Value of Stock Options Using Black-Scholes Option Pricing Model (Detail) - $ / shares
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Market-leveraged stock units [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Expected stock price volatility 32.90% 42.20% 42.20%
Risk-free interest rate 1.00% 0.70% 0.40%
Expected dividend yield 0.00% 0.00% 0.00%
Weighted average estimated fair value of options at grant date $ 15.11 $ 20.38 $ 21.09
Stock Options [Member] | Market Condition Vesting [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Expected stock price volatility 45.60%   66.80%
Risk-free interest rate 1.80%   1.40%
Expected life of options (years) 6 years   6 years
Expected dividend yield 0.00%   0.00%
Weighted average estimated fair value of options at grant date $ 6.51   $ 11.47
Management [Member] | Stock Options [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Expected stock price volatility 61.40%    
Risk-free interest rate 2.20%    
Expected dividend yield 0.00%    
Weighted average estimated fair value of options at grant date $ 7.87    
v3.3.1.900
Retirement Plans - Additional Information (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]      
Expense of defined contribution retirement plans $ 1,255 $ 1,651 $ 1,456
Unfunded liability for supplemental plan $ 802 $ 715  
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Detail)
bbl in Thousands, Mcf in Thousands
 12 Months Ended
Dec. 31, 2015
Well
Dec. 31, 2015
$ / MMBTU
Dec. 31, 2015
bbl
Dec. 31, 2015
$ / Boe
Dec. 31, 2015
Mcf
Dec. 31, 2014
Well
$ / MMBTU
$ / Boe
bbl
Mcf
Dec. 31, 2013
Well
$ / MMBTU
$ / Boe
bbl
Mcf
Supplemental Oil And Gas Reserve Information [Line Items]              
New well addition | Well 36         106 88
Crude Oil and NGL [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Average spot price | $ / Boe       50.28   94.99 96.91
Natural Gas in Mmbtu [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Average spot price | $ / MMBTU   2.59       4.35 3.67
Consolidated Entities [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates           608 1,243
Oil [Member] | Consolidated Entities [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Extensions and discoveries [1]     224     2,191 3,085
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place [1]     704     105  
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates [1]     855     608 182
Oil [Member] | Equity Method Investee [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates [1]     0     0 0
New PDP Reserves [Member] | Consolidated Entities [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Extensions and discoveries           694  
New PUD Reserves [Member] | Consolidated Entities [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Extensions and discoveries           913  
Natural Gas [Member] | Consolidated Entities [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Extensions and discoveries | Mcf         173 774 2,046
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | Mcf         1,223 218  
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates     1,995   1,675 293 1,243
Natural Gas [Member] | Equity Method Investee [Member]              
Supplemental Oil And Gas Reserve Information [Line Items]              
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | Mcf         (320) (382) 7
[1] Includes natural gas liquids (NGLs).
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited) - Summary of Estimated Quantities of Proved Developed Oil and Natural Gas Reserves (Detail)
bbl in Thousands, Mcf in Thousands
 12 Months Ended
Dec. 31, 2015
bbl
Mcf
Dec. 31, 2015
bbl
Mcf
Dec. 31, 2014
bbl
Mcf
Dec. 31, 2013
bbl
Mcf
Oil [Member]        
Reserve Quantities [Line Items]        
Beginning Balance [1] 7,672   5,824  
Proved developed reserves [1] 5,179 5,179 5,269 3,893
Proved undeveloped reserves [1] 0 0 2,403 1,931
Ending Balance [1] 5,179   7,672 5,824
Natural Gas [Member]        
Reserve Quantities [Line Items]        
Beginning Balance | Mcf   14,400 15,962  
Proved developed reserves | Mcf 9,220 9,220 12,599 13,717
Proved undeveloped reserves | Mcf 0 0 1,801 2,245
Ending Balance | Mcf   9,220 14,400 15,962
Consolidated Entities [Member]        
Reserve Quantities [Line Items]        
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates     (608) (1,243)
Consolidated Entities [Member] | Oil [Member]        
Reserve Quantities [Line Items]        
Beginning Balance [1] 7,672   5,824 3,220
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates [1] (855)   (608) (182)
Extensions and discoveries [1] 224   2,191 3,085
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place [1] (704)   (105)  
Acquisitions [1] 0   85 35
Production [1] (1,158)   (931) (698)
Ending Balance [1] 5,179   7,672 5,824
Consolidated Entities [Member] | Natural Gas [Member]        
Reserve Quantities [Line Items]        
Beginning Balance | Mcf   12,649 13,630 11,722
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates (1,995) (1,675) (293) (1,243)
Extensions and discoveries | Mcf   173 774 2,046
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | Mcf   (1,223) (218)  
Acquisitions | Mcf   0 31 531
Production | Mcf   (1,967) (1,861) (1,912)
Ending Balance | Mcf   7,957 12,649 13,630
Equity Method Investee [Member] | Oil [Member]        
Reserve Quantities [Line Items]        
Beginning Balance [1] 0   0 0
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates [1] 0   0 0
Production [1] 0   0 0
Ending Balance [1] 0   0 0
Equity Method Investee [Member] | Natural Gas [Member]        
Reserve Quantities [Line Items]        
Beginning Balance | Mcf   1,751 2,332 2,572
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | Mcf   320 382 (7)
Production | Mcf   (168) (199) (247)
Ending Balance | Mcf   1,263 1,751 2,332
[1] Includes natural gas liquids (NGLs).
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Cost Related to Oil and Natural Gas Producing Activities (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Capitalized Costs Relating To Oil And Gas Producing Activities [Line Items]    
Total costs $ 138,855 $ 311,745
Consolidated Entities [Member]    
Capitalized Costs Relating To Oil And Gas Producing Activities [Line Items]    
Unproved oil and gas properties 19,441 90,446
Proved oil and gas properties 119,414 221,299
Total costs 138,855 311,745
Less accumulated depreciation, depletion and amortization (58,242) (48,252)
Net capitalized costs $ 80,613 $ 263,493
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]        
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves $ 67,498 $ 165,616 $ 136,853 $ 107,956
Consolidated Entities [Member]        
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]        
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Cash Inflows 216,588 665,657 544,098  
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves 0 2,001 0  
Costs Incurred, Acquisition of Unproved Oil and Gas Properties 4,832 25,666 35,806  
Exploration costs 17,922 39,399 10,486  
Development costs 27,609 40,277 54,538  
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities 50,363 107,343 100,830  
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Production Costs 93,623 271,735 231,801  
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Income Tax Expense 22,218 106,002 77,361  
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows 100,747 287,920 234,936  
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Ten Percent Annual Discount for Estimated Timing of Cash Flows 33,951 124,079 99,383  
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves $ 66,796 $ 163,841 $ 135,553 $ 106,543
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited) - Estimates of Future Cash Flows from Proved Developed Oil and Natural Gas Reserves (Detail) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]        
Standardized measure of discounted future net cash flows $ 67,498 $ 165,616 $ 136,853 $ 107,956
Consolidated Entities [Member]        
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]        
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Cash Inflows 216,588 665,657 544,098  
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Production Costs (93,623) (271,735) (231,801)  
Future income tax expenses (22,218) (106,002) (77,361)  
Future net cash flows 100,747 287,920 234,936  
10% annual discount for estimated timing of cash flows (33,951) (124,079) (99,383)  
Standardized measure of discounted future net cash flows 66,796 163,841 135,553 106,543
Equity Method Investee [Member]        
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]        
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Cash Inflows 2,283 6,186 4,765  
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Production Costs (245) (664) (512)  
Future income tax expenses (774) (2,098) (1,616)  
Future net cash flows 1,264 3,424 2,637  
10% annual discount for estimated timing of cash flows (562) (1,649) (1,337)  
Standardized measure of discounted future net cash flows $ 702 $ 1,775 $ 1,300 $ 1,413
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited) - Changes in Standardized Measure of Discounted Future Net Cash Flow (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]      
Beginning Balance $ 165,616 $ 136,853 $ 107,956
Changes resulting from:      
Net change in sales prices and production costs (137,648) 507 23,837
Net change in future development costs 92 1,308 (2,897)
Sales of oil and gas, net of production costs (32,160) (63,979) (57,360)
Net change due to extensions and discoveries 11,747 58,228 54,539
Increase Due to Purchases of Minerals in Place 0 2,778 1,160
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (15,855) (5,804)  
Net change due to revisions of quantity estimates (15,431) 14,960 8,679
Previously estimated development costs incurred (15,096) (15,497) (4,124)
Accretion of discount 22,886 18,277 13,768
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Other 3,808 4,313 (749)
Net change in income taxes 49,347 (17,322) (16,204)
Aggregate change for the year (98,118) 28,763 28,897
Ending Balance 67,498 165,616 136,853
Consolidated Entities [Member]      
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]      
Beginning Balance 163,841 135,553 106,543
Changes resulting from:      
Net change in sales prices and production costs (136,536) (1,064) 23,422
Net change in future development costs 92 1,308 (2,897)
Sales of oil and gas, net of production costs (31,732) (63,192) (56,559)
Net change due to extensions and discoveries 11,747 58,228 54,539
Increase Due to Purchases of Minerals in Place 0 2,778 1,160
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (15,855) (5,804)  
Net change due to revisions of quantity estimates (15,164) 15,303 8,673
Previously estimated development costs incurred (15,096) (15,497) (4,124)
Accretion of discount 22,600 18,067 13,540
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Other 4,018 4,198 (718)
Net change in income taxes 48,689 (17,031) (16,274)
Aggregate change for the year (97,045) 28,288 29,010
Ending Balance 66,796 163,841 135,553
Equity Method Investee [Member]      
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]      
Beginning Balance 1,775 1,300 1,413
Changes resulting from:      
Net change in sales prices and production costs (1,112) 1,571 415
Net change in future development costs 0 0 0
Sales of oil and gas, net of production costs (428) (787) (801)
Net change due to extensions and discoveries 0 0 0
Increase Due to Purchases of Minerals in Place 0 0 0
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place   0  
Net change due to revisions of quantity estimates (267) (343) 6
Previously estimated development costs incurred 0 0 0
Accretion of discount 286 210 228
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Other (210) 115 (31)
Net change in income taxes 658 (291) 70
Aggregate change for the year (1,073) 475 (113)
Ending Balance $ 702 $ 1,775 $ 1,300
v3.3.1.900
Supplemental Oil and Gas Disclosures (Unaudited) - Information About Results of Operations of Oil and Natural Gas Interests (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Consolidated entities      
Results of operations $ (170,567) $ (19,703) $ 8,490
Consolidated Entities [Member]      
Consolidated entities      
Revenues 51,553 82,919 69,036
Production costs (19,820) (19,727) (12,477)
Exploration costs (11,864) (17,416) (10,486)
Depreciation, depletion, amortization (28,774) (29,442) (19,552)
Results of Operations, Impairment of Oil and Gas Properties (164,831) (32,665) (473)
Oil and gas administrative expenses (11,700) (17,000) (14,407)
Results of Operations, Accretion of Asset Retirement Obligations (144) (121) (94)
Income tax expenses 14,717 13,398 (3,471)
Results of operations (170,863) (20,054) 8,076
Equity Method Investee [Member]      
Consolidated entities      
Royalty revenues 428 786 801
Production costs (102) (105) (123)
Oil and gas administrative expenses (51) (95) (86)
Income tax expenses 21 (235) (178)
Results of operations $ 296 $ 351 $ 414
v3.3.1.900
Summary of Quarterly Results of Operations - Summary of Quarterly Results of Operations (Detail) - USD ($)
$ / shares in Units, $ in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]                      
Impairment of Oil and Gas Properties $ 37,646 $ 81,240 $ 45,938 $ 7 $ 30,591 $ 735 $ 584 $ 755 $ 164,831 $ 32,665  
Total revenues 114,018 [1] 43,168 [1] 57,430 [1] 47,805 [1] 80,316 [1] 58,840 [1] 83,013 [1] 84,605 [1] 262,421 306,774 $ 331,045
Gross profit [1] 8,341 (69,572) (35,009) 17,289 (6,259) 19,606 33,261 35,025      
Operating income (loss) (9,482) [1] (94,751) [1] (52,714) [1] (7,737) [1] (16,783) [1] 12,716 [1] 26,942 [1] 15,883 [1] (164,684) 38,758 46,577
Equity in earnings of unconsolidated ventures 4,470 [1] 2,909 [1] 5,584 [1] 3,045 [1] 4,720 [1] 2,016 [1] 958 [1] 991 [1] 16,008 8,685 8,737
Income (loss) before taxes (11,983) [1] (100,095) [1] (55,062) [1] (12,596) [1] (18,713) [1] 7,994 [1] 22,799 [1] 13,665 [1] (179,736) 25,745 42,269
Net income (loss) attributable to Forestar Group Inc. $ (6,166) [1] $ (164,216) [1] $ (34,507) [1] $ (8,158) [1] $ (11,800) [1] $ 5,227 [1] $ 14,822 [1] $ 8,334 [1] $ (213,047) $ 16,583 $ 29,321
Net income (loss) per share - basic $ (0.18) [1] $ (4.79) [1] $ (1.01) [1] $ (0.24) [1] $ (0.34) [1] $ 0.12 [1] $ 0.34 [1] $ 0.20 [1] $ (6.22) $ 0.38 $ 0.81
Net income (loss) per share - diluted $ (0.18) [1] $ (4.79) [1] $ (1.01) [1] $ (0.24) [1] $ (0.34) [1] $ 0.12 [1] $ 0.34 [1] $ 0.19 [1] $ (6.22) $ 0.38 $ 0.80
[1] Non-cash impairment charges for unproved leasehold interests and proved oil and gas properties included in our quarterly financial results are as follows: First Quarter Second Quarter Third Quarter FourthQuarter (In thousands)2015$7 $45,938 $81,240 $37,6462014755 584 735 30,591
v3.3.1.900
Subsequent Events (Details) - Disposal Group, Not Discontinued Operations [Member] - Subsequent Event [Member]
Mar. 01, 2016
USD ($)
$ / bbl
Feb. 04, 2016
USD ($)
Kansas and Nebraska Oil and Gas Properties [Member]    
Subsequent Event [Line Items]    
Purchase price of properties sold $ 21,000,000  
Contingent payment for properties sold $ 2,000,000  
Minimum WTI oil price for contingent consideration (in US$ per Bbl) | $ / bbl 60  
Minimum duration of WTI oil price at $60 per Bbl 60 days  
Disposal Group, Including Discontinued Operation, Contingent Consideration, Minimum Oil Price Duration Following Close Period 1 year  
Radisson Hotel & Suites, Austin [Member]    
Subsequent Event [Line Items]    
Purchase price of properties sold   $ 130,000,000
v3.3.1.900
Schedule III - Consolidated Real Estate and Accumulated Depreciation (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2012
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 383,570      
Buildings & Improvements 56,559      
Improvements less Cost of Sales and Other 169,624      
Carrying Costs [1] 9,091      
Land & Land Improvements 509,999      
Buildings & Improvements 108,845      
Total 618,844 $ 607,133 $ 547,530 $ 545,370
Accumulated depreciation (32,129) $ (31,377) $ (28,066) $ (28,220)
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances 43,691      
Entitled, developed and under development projects [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 283,025      
Improvements less Cost of Sales and Other 60,025      
Carrying Costs [1] 9,091      
Land & Land Improvements 352,141      
Total 352,141      
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances 4,355      
Entitled, developed and under development projects [Member] | Other County [Member] | Other Property [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 8,443      
Improvements less Cost of Sales and Other (4,097)      
Carrying Costs [1] 653      
Land & Land Improvements 4,999      
Total 4,999      
Entitled, developed and under development projects [Member] | TENNESSEE | Williamson County [Member] | Morgan Farms [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 6,841      
Improvements less Cost of Sales and Other (552)      
Carrying Costs [1] 166      
Land & Land Improvements 6,455      
Total $ 6,455      
Date of Construction 2013      
Date Acquired 2013      
Entitled, developed and under development projects [Member] | TENNESSEE | Williamson County [Member] | Vickery Park [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 3,575      
Improvements less Cost of Sales and Other 560      
Land & Land Improvements 4,135      
Total $ 4,135      
Date Acquired 2015      
Entitled, developed and under development projects [Member] | TENNESSEE | Williamson County [Member] | Weatherford Estates [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 856      
Improvements less Cost of Sales and Other 1,603      
Land & Land Improvements 2,459      
Total $ 2,459      
Date of Construction 2015      
Date Acquired 2014      
Entitled, developed and under development projects [Member] | TENNESSEE | Williamson County [Member] | Beckwith Crossing [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 1,294      
Improvements less Cost of Sales and Other 2,519      
Land & Land Improvements 3,813      
Total $ 3,813      
Date of Construction 2015      
Date Acquired 2014      
Entitled, developed and under development projects [Member] | ARIZONA | Pima County [Member] | Dove Mountain [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 5,860      
Improvements less Cost of Sales and Other 3      
Land & Land Improvements 5,863      
Total $ 5,863      
Date Acquired 2015      
Entitled, developed and under development projects [Member] | California [Member] | Contra Costa County [Member] | San Joaquin River [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 12,225      
Improvements less Cost of Sales and Other (3,310)      
Land & Land Improvements 8,915      
Total 8,915      
Entitled, developed and under development projects [Member] | COLORADO | Douglas County [Member] | Pinery West [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 7,308      
Improvements less Cost of Sales and Other 3,691      
Land & Land Improvements 10,999      
Total $ 10,999      
Date of Construction 2006      
Date Acquired 2006      
Entitled, developed and under development projects [Member] | COLORADO | Weld County [Member] | Buffalo Highlands [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 3,001      
Improvements less Cost of Sales and Other 547      
Land & Land Improvements 3,548      
Total $ 3,548      
Date of Construction 2006      
Date Acquired 2005      
Entitled, developed and under development projects [Member] | COLORADO | Weld County [Member] | Johnstown Farms [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 2,749      
Improvements less Cost of Sales and Other 4,024      
Carrying Costs [1] 188      
Land & Land Improvements 6,961      
Total $ 6,961      
Date of Construction 2002      
Date Acquired 2002      
Entitled, developed and under development projects [Member] | COLORADO | Weld County [Member] | Stone Braker [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 3,878      
Improvements less Cost of Sales and Other (1,469)      
Land & Land Improvements 2,409      
Total $ 2,409      
Date of Construction 2005      
Date Acquired 2005      
Entitled, developed and under development projects [Member] | Georgia [Member] | Cobb County [Member] | West Oaks [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 1,669      
Improvements less Cost of Sales and Other 232      
Land & Land Improvements 1,901      
Total $ 1,901      
Date of Construction 2015      
Date Acquired 2015      
Entitled, developed and under development projects [Member] | Georgia [Member] | Paulding County [Member] | Harris Place [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 265      
Improvements less Cost of Sales and Other (111)      
Land & Land Improvements 154      
Total $ 154      
Date Acquired 2012      
Entitled, developed and under development projects [Member] | Georgia [Member] | Paulding County [Member] | Seven Hills [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 2,964      
Improvements less Cost of Sales and Other 145      
Land & Land Improvements 3,109      
Total $ 3,109      
Date Acquired 2012      
Entitled, developed and under development projects [Member] | South Carolina [Member] | York County [Member] | Habersham [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 3,877      
Improvements less Cost of Sales and Other 3,072      
Carrying Costs [1] 239      
Land & Land Improvements 7,188      
Total $ 7,188      
Date of Construction 2014      
Date Acquired 2013      
Entitled, developed and under development projects [Member] | South Carolina [Member] | Lancaster County [Member] | Ansley [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 5,089      
Improvements less Cost of Sales and Other 574      
Land & Land Improvements 5,663      
Total $ 5,663      
Date Acquired 2015      
Entitled, developed and under development projects [Member] | North Carolina [Member] | Mechlanburg County [Member] | Walden [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 12,085      
Improvements less Cost of Sales and Other 345      
Land & Land Improvements 12,430      
Total $ 12,430      
Date Acquired 2015      
Entitled, developed and under development projects [Member] | Texas [Member] | Hays County [Member] | Arrowhead Ranch [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 12,856      
Improvements less Cost of Sales and Other 6,537      
Land & Land Improvements 19,393      
Total $ 19,393      
Date of Construction 2015      
Date Acquired 2007      
Entitled, developed and under development projects [Member] | Texas [Member] | Williamson County [Member] | La Conterra [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 4,024      
Improvements less Cost of Sales and Other (2,790)      
Carrying Costs [1] 293      
Land & Land Improvements 1,527      
Total $ 1,527      
Date Acquired 2006      
Entitled, developed and under development projects [Member] | Texas [Member] | Williamson County [Member] | Westside at Buttercup Creek [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 13,149      
Improvements less Cost of Sales and Other (13,586)      
Carrying Costs [1] 488      
Land & Land Improvements 51      
Total $ 51      
Date of Construction 1993      
Date Acquired 1993      
Entitled, developed and under development projects [Member] | Texas [Member] | Tarrant County [Member] | Summer Creek Ranch [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 2,887      
Improvements less Cost of Sales and Other (1,601)      
Land & Land Improvements 1,286      
Total $ 1,286      
Date Acquired 2012      
Entitled, developed and under development projects [Member] | Texas [Member] | Tarrant County [Member] | Bar C Ranch [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 1,365      
Improvements less Cost of Sales and Other 3,258      
Carrying Costs [1] 32      
Land & Land Improvements 4,655      
Total $ 4,655      
Date Acquired 2012      
Entitled, developed and under development projects [Member] | Texas [Member] | Nueces County [Member] | Tortuga Dunes [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 12,080      
Improvements less Cost of Sales and Other 9,670      
Land & Land Improvements 21,750      
Total $ 21,750      
Date Acquired 2006      
Entitled, developed and under development projects [Member] | Texas [Member] | Calhoun County [Member] | Caracol [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 8,603      
Improvements less Cost of Sales and Other 3,688      
Carrying Costs [1] 2,047      
Land & Land Improvements 14,338      
Total $ 14,338      
Date of Construction 2006      
Date Acquired 2006      
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances $ 2,237      
Entitled, developed and under development projects [Member] | Texas [Member] | Bastrop County [Member] | Hunters Crossing [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 3,613      
Improvements less Cost of Sales and Other 5,180      
Carrying Costs [1] 358      
Land & Land Improvements 9,151      
Total $ 9,151      
Date of Construction 2001      
Date Acquired 2001      
Entitled, developed and under development projects [Member] | Texas [Member] | Bastrop County [Member] | The Colony [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 8,726      
Improvements less Cost of Sales and Other 15,206      
Carrying Costs [1] 161      
Land & Land Improvements 24,093      
Total $ 24,093      
Date of Construction 1999      
Date Acquired 1999      
Entitled, developed and under development projects [Member] | Texas [Member] | Bexar County [Member] | Cibolo Canyons [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 17,305      
Improvements less Cost of Sales and Other 40,243      
Carrying Costs [1] 1,202      
Land & Land Improvements 58,750      
Total $ 58,750      
Date of Construction 2004      
Date Acquired 1986      
Entitled, developed and under development projects [Member] | Texas [Member] | Harris County [Member] | City Park [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 3,946      
Improvements less Cost of Sales and Other 1,463      
Carrying Costs [1] 1,641      
Land & Land Improvements 7,050      
Total $ 7,050      
Date of Construction 2002      
Date Acquired 2001      
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances $ 1,659      
Entitled, developed and under development projects [Member] | Texas [Member] | Harris County [Member] | Barrington [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 8,950      
Improvements less Cost of Sales and Other (7,062)      
Land & Land Improvements 1,888      
Total $ 1,888      
Date Acquired 2011      
Entitled, developed and under development projects [Member] | Texas [Member] | Harris County [Member] | Imperial Forest [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 5,345      
Improvements less Cost of Sales and Other 819      
Land & Land Improvements 6,164      
Total $ 6,164      
Date of Construction 2015      
Date Acquired 2014      
Entitled, developed and under development projects [Member] | Texas [Member] | Collin County [Member] | Lakes Of Prosper [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 8,951      
Improvements less Cost of Sales and Other (3,550)      
Carrying Costs [1] 180      
Land & Land Improvements 5,581      
Total $ 5,581      
Date Acquired 2012      
Entitled, developed and under development projects [Member] | Texas [Member] | Collin County [Member] | Maxwell Creek [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 9,904      
Improvements less Cost of Sales and Other (7,946)      
Carrying Costs [1] 635      
Land & Land Improvements 2,593      
Total $ 2,593      
Date of Construction 2000      
Date Acquired 2000      
Entitled, developed and under development projects [Member] | Texas [Member] | Collin County [Member] | Park Place [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 2,177      
Improvements less Cost of Sales and Other 3,661      
Land & Land Improvements 5,838      
Total $ 5,838      
Date of Construction 2014      
Date Acquired 2013      
Entitled, developed and under development projects [Member] | Texas [Member] | Collin County [Member] | Timber Creek [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 7,282      
Improvements less Cost of Sales and Other 9,137      
Land & Land Improvements 16,419      
Total $ 16,419      
Date of Construction 2007      
Date Acquired 2007      
Entitled, developed and under development projects [Member] | Texas [Member] | Collin County [Member] | Village Park [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 4,772      
Improvements less Cost of Sales and Other (4,765)      
Carrying Costs [1] 45      
Land & Land Improvements 52      
Total $ 52      
Date Acquired 2012      
Entitled, developed and under development projects [Member] | Texas [Member] | Comal County [Member] | Oak Creek Estates [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 1,921      
Improvements less Cost of Sales and Other 2,314      
Carrying Costs [1] 175      
Land & Land Improvements 4,410      
Total $ 4,410      
Date of Construction 2006      
Date Acquired 2005      
Entitled, developed and under development projects [Member] | Texas [Member] | Dallas County [Member] | Stoney Creek [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 12,822      
Improvements less Cost of Sales and Other 2,783      
Carrying Costs [1] 49      
Land & Land Improvements 15,654      
Total $ 15,654      
Date of Construction 2007      
Date Acquired 2007      
Entitled, developed and under development projects [Member] | Texas [Member] | Denton County [Member] | Lantana [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 27,673      
Improvements less Cost of Sales and Other (7,382)      
Land & Land Improvements 20,291      
Total $ 20,291      
Date of Construction 2000      
Date Acquired 1999      
Entitled, developed and under development projects [Member] | Texas [Member] | Denton County [Member] | River's Edge [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 1,227      
Improvements less Cost of Sales and Other 381      
Land & Land Improvements 1,608      
Total $ 1,608      
Date Acquired 2014      
Entitled, developed and under development projects [Member] | Texas [Member] | Denton County [Member] | The Preserve At Pecan Creek [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 5,855      
Improvements less Cost of Sales and Other (3,905)      
Carrying Costs [1] 436      
Land & Land Improvements 2,386      
Total $ 2,386      
Date of Construction 2006      
Date Acquired 2005      
Entitled, developed and under development projects [Member] | Texas [Member] | Fort Bend County [Member] | Summer Lakes [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 4,269      
Improvements less Cost of Sales and Other 968      
Land & Land Improvements 5,237      
Total $ 5,237      
Date of Construction 2013      
Date Acquired 2012      
Entitled, developed and under development projects [Member] | Texas [Member] | Fort Bend County [Member] | Summer Park [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 4,804      
Improvements less Cost of Sales and Other 57      
Land & Land Improvements 4,861      
Total $ 4,861      
Date of Construction 2013      
Date Acquired 2012      
Entitled, developed and under development projects [Member] | Texas [Member] | Fort Bend County [Member] | Willow Creek Farms [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 3,479      
Improvements less Cost of Sales and Other (311)      
Carrying Costs [1] 90      
Land & Land Improvements 3,258      
Total $ 3,258      
Date of Construction 2012      
Date Acquired 2012      
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances $ 459      
Entitled, developed and under development projects [Member] | Missouri [Member] | Clay County [Member] | Somerbrook [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 3,061      
Improvements less Cost of Sales and Other (218)      
Carrying Costs [1] 13      
Land & Land Improvements 2,856      
Total $ 2,856      
Date of Construction 2003      
Date Acquired 2001      
Undeveloped Land Type [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 61,742      
Improvements less Cost of Sales and Other 36,439      
Carrying Costs [1] 0      
Land & Land Improvements 98,181      
Total 98,181      
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances 0      
Undeveloped Land Type [Member] | Other County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 9,170      
Improvements less Cost of Sales and Other 7,661      
Land & Land Improvements 16,831      
Total 16,831      
Undeveloped Land Type [Member] | California [Member] | Los Angeles [Member] | Land In Entitlement Process [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 3,950      
Improvements less Cost of Sales and Other 19,564      
Land & Land Improvements 23,514      
Total $ 23,514      
Date Acquired 1997      
Undeveloped Land Type [Member] | Georgia [Member] | Coweta County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 3,089      
Improvements less Cost of Sales and Other 1,343      
Land & Land Improvements 4,432      
Total 4,432      
Undeveloped Land Type [Member] | Georgia [Member] | Dawson County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 2,228      
Improvements less Cost of Sales and Other 3,381      
Land & Land Improvements 5,609      
Total 5,609      
Undeveloped Land Type [Member] | Georgia [Member] | Dawson County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 3,150      
Improvements less Cost of Sales and Other (108)      
Land & Land Improvements 3,042      
Total 3,042      
Undeveloped Land Type [Member] | Georgia [Member] | Polk County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 2,354      
Improvements less Cost of Sales and Other (198)      
Land & Land Improvements 2,156      
Total 2,156      
Undeveloped Land Type [Member] | Georgia [Member] | Bexar County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Improvements less Cost of Sales and Other 3,036      
Land & Land Improvements 3,036      
Total 3,036      
Undeveloped Land Type [Member] | Georgia [Member] | Harris County [Member] | Land In Entitlement Process [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 685      
Improvements less Cost of Sales and Other 1,151      
Land & Land Improvements 1,836      
Total 1,836      
Undeveloped Land Type [Member] | Georgia [Member] | Bartow County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 4,057      
Improvements less Cost of Sales and Other (2,440)      
Land & Land Improvements 1,617      
Total 1,617      
Undeveloped Land Type [Member] | Georgia [Member] | Carroll County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 13,564      
Improvements less Cost of Sales and Other 2,580      
Land & Land Improvements 16,144      
Total 16,144      
Undeveloped Land Type [Member] | Georgia [Member] | Cherokee County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 6,043      
Improvements less Cost of Sales and Other 536      
Land & Land Improvements 6,579      
Total 6,579      
Undeveloped Land Type [Member] | Georgia [Member] | Gilmer County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 2,748      
Improvements less Cost of Sales and Other (62)      
Land & Land Improvements 2,686      
Total 2,686      
Undeveloped Land Type [Member] | Georgia [Member] | Haralson County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 195      
Improvements less Cost of Sales and Other 88      
Land & Land Improvements 283      
Total 283      
Undeveloped Land Type [Member] | Georgia [Member] | Lumpkin County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 3,015      
Improvements less Cost of Sales and Other (93)      
Land & Land Improvements 2,922      
Total 2,922      
Undeveloped Land Type [Member] | Georgia [Member] | Paulding County [Member] | Undeveloped Land [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 7,494      
Improvements less Cost of Sales and Other      
Land & Land Improvements $ 7,494      
Total 7,494      
Income Producing Properties [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 38,803      
Buildings & Improvements 56,559      
Improvements less Cost of Sales and Other 73,160      
Carrying Costs [1] 0      
Land & Land Improvements 59,677      
Buildings & Improvements 108,845      
Total 168,522      
Accumulated depreciation (32,129)      
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances 39,336      
Income Producing Properties [Member] | TENNESSEE | Davidson County [Member] | Westmont [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 6,607      
Improvements less Cost of Sales and Other 3,340      
Land & Land Improvements 9,947      
Total $ 9,947      
Date Acquired 2014      
Income Producing Properties [Member] | North Carolina [Member] | Mechlanburg County [Member] | East Morehead [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 5,779      
Improvements less Cost of Sales and Other 14,208      
Land & Land Improvements 19,987      
Total $ 19,987      
Date Acquired 2012      
Income Producing Properties [Member] | Texas [Member] | Travis County [Member] | Radisson Hotel And Suites [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Buildings & Improvements $ 10,603      
Improvements less Cost of Sales and Other 52,286      
Land & Land Improvements 0      
Buildings & Improvements 62,889      
Total 62,889      
Accumulated depreciation (29,268)      
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances 15,400      
Income Producing Properties [Member] | Texas [Member] | Travis County [Member] | Eleven [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 7,940      
Buildings & Improvements 45,956      
Improvements less Cost of Sales and Other 0      
Land & Land Improvements 7,940      
Buildings & Improvements 45,956      
Total 53,896      
Accumulated depreciation $ (2,861)      
Date of Construction 2013      
Date Acquired 2014      
SEC Schedule III, Real Estate and Accumulated Depreciation, Amount of Encumbrances $ 23,936      
Income Producing Properties [Member] | Texas [Member] | Travis County [Member] | Downtown Edge [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land 11,202      
Improvements less Cost of Sales and Other 1,504      
Land & Land Improvements 12,706      
Total $ 12,706      
Date Acquired 2014      
Income Producing Properties [Member] | Texas [Member] | Travis County [Member] | West Austin [Member]        
Real Estate and Accumulated Depreciation [Line Items]        
Land $ 7,275      
Improvements less Cost of Sales and Other 1,822      
Land & Land Improvements 9,097      
Total $ 9,097      
Date Acquired 2014      
[1] Includes natural gas liquids (NGLs).
v3.3.1.900
Schedule III - Reconciliation of Real Estate and Accumulated Depreciation (Detail) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
SEC Schedule III, Real Estate and Accumulated Depreciation Disclosure [Abstract]      
Beginning balance $ 607,133 $ 547,530 $ 545,370
Amounts capitalized 124,633 214,184 111,428
Amounts retired or adjusted (112,922) (154,581) (109,268)
Ending balance 618,844 607,133 547,530
Beginning balance (31,377) (28,066) (28,220)
Depreciation expense (6,810) (3,319) (2,185)
Amounts retired or adjusted 6,058 8 2,339
Ending balance $ (32,129) $ (31,377) $ (28,066)
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