UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 8-K
 
CURRENT REPORT
Pursuant to Section 13 or Section 15(d) of
the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): September 18, 2014
  
CHAPARRAL ENERGY, INC.
(Exact name of registrant as specified in its charter)
 
 
 
 
 
 
Delaware
 
333-134748
 
73-1590941
(State or other jurisdiction
of incorporation)
 
(Commission
File Number)
 
(IRS Employer
Identification No.)
 
 
 
701 Cedar Lake Boulevard
Oklahoma City, OK
 
73114
(Address of principal executive offices)
 
(Zip Code)
Registrant's telephone number, including area code: (405) 478-8770
Not Applicable
(Former name or former address, if changed since last report)
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
 
o
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
 
o
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
 
o
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
 
o
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))



Item 7.01.
Regulation FD Disclosure.
On September 18, 2014, Chaparral Energy, Inc. (referred to herein as “we”, “us,” and “our”) presented the slide show, attached hereto as Exhibit 99.1 and incorporated herein by reference, at the 2014 Credit Suisse Global Credit Products Conference in Miami, Florida.
Note Regarding Non-GAAP Financial Measures
The investor presentation attached as an exhibit hereto contains certain references to adjusted EBITDA value, which is a non-GAAP financial measure, as defined under Regulation G of the rules and regulations of the SEC.
Adjusted EBITDA
Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our senior secured revolving credit facility as described in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in our Quarterly Report on Form 10-Q for the six months ended June 30, 2014. We consider compliance with this covenant to be material. The calculation of Consolidated EBITDAX includes pro forma adjustments for property acquisitions and dispositions, and as a result of these adjustments, our Consolidated EBITDAX as calculated for covenant compliance purposes is higher than our adjusted EBITDA for the year ended December 31, 2013 and lower than our adjusted EBITDA for the four consecutive fiscal quarters ending ending June 30, 2014.
Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.
We define adjusted EBITDA as net income (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedge reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges.


 

2


The following table provides a reconciliation of our net (loss) income to adjusted EBITDA for the specified periods:

 
 
Six months ended June 30,
 
Year ended December 31,
(in thousands)
 
2014
 
2013
 
2012
 
2011
 
2010
 
2009
Net (loss) income
 
$
(4,028
)
 
$
55,687

 
$
64,403

 
$
42,048

 
$
33,713

 
$
(144,318
)
Interest expense
 
52,662

 
96,876

 
98,402

 
96,720

 
81,370

 
90,102

Income tax (benefit) expense
 
(2,419
)
 
32,849

 
37,837

 
35,924

 
23,803

 
(85,936
)
Depreciation, depletion, and amortization
 
119,104

 
192,426

 
169,307

 
146,083

 
109,503

 
104,734

Reclassification adjustment for hedge (gains) losses
 
—

 
(37,134
)
 
(46,746
)
 
27,452

 
23,889

 
(21,752
)
Non-cash change in fair value of non-hedge derivative instruments
 
64,881

 
40,748

 
(12,411
)
 
(57,899
)
 
(2,523
)
 
149,106

Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date included in EBITDA (1)
 
—

 
—

 
—

 
—

 
9,418

 
—

Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date excluded from EBITDA (1)
 
—

 
—

 
—

 
—

 
—

 
(102,352
)
Interest income
 
(71
)
 
(254
)
 
(225
)
 
(165
)
 
(144
)
 
(283
)
Stock-based compensation expense
 
2,260

 
4,933

 
3,065

 
3,747

 
2,600

 
1,145

Gain on disposed assets
 
(811
)
 
(670
)
 
(149
)
 
(1,284
)
 
(184
)
 
(10,463
)
Loss on extinguishment of debt
 
—

 
—

 
21,714

 
20,592

 
2,241

 
—

Loss on impairment of other assets
 
—

 
3,490

 
2,000

 
—

 
—

 
240,790

Other non-cash charges
 
—

 
—

 
—

 
—

 
4,150

 
2,928

Adjusted EBITDA
 
$
231,578

 
$
388,951

 
$
337,197

 
$
313,218

 
$
287,836

 
$
223,701

________________
(1)  Through March 31, 2010, our calculation of adjusted EBITDA excluded any cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization.


Item 9.01.
Financial Statements and Exhibits.
 
 
(d)
Exhibits.
 
 
 
 
Exhibit
Number
 
Description
 
 
 
99.1
 
Investor Presentation


3


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 

 
 
 
 
 
 
 
 
September 18, 2014
 
 
 
 
 
 
 
 
 
 
 
By:
 
/s/    JOSEPH O. EVANS        
 
 
 
 
 
Name:
 
Joseph O. Evans
 
 
 
 
 
Title:
 
Chief Financial Officer and Executive Vice President
 

4


Exhibit Index
 

 
 
 
Exhibit
Number
 
Description
 
 
 
99.1
 
Investor Presentation



5
creditsuissepresentation
September 2014 Credit Suisse

 
Company Representatives 2 Mark Fischer Chief Executive Officer Joe Evans Chief Financial Officer

 
This presentation contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices, the uncertain economic conditions in the United States and globally, the decline in the values of our properties that have resulted in and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, the impact of hurricanes and other natural disasters on our present and future operations, the impact of government regulation, and the operating hazards attendant to the oil and natural gas business. In particular, careful consideration should be given to cautionary statements made in the various reports we have filed with the Securities and Exchange Commission. We undertake no duty to update or revise these forward-looking statements. Forward-Looking Statements 3

 
Chaparral: Overview

 
2014 Highlights 5 53%33% 14% Q2 2014 Production by Product Oil Gas NGLs Net Production Q2 2014 Q2 YTD 2014 Oil (MBbls) 1,528 2,943 Gas (MBoe) 937 1,799 NGLs (MBbls) 394 708 Total (MBoe) 2,859 5,450 head2right Q2 production volume increase of 15% year over year to 31,418 Boe per day head2right Record EBITDA of $121 million in Q2 head2right Q2 capital expenditures of $195 million head2right Exceptional operational execution • Drilled 35 new wells during the quarter - 7 NOMP - 14 EOR - 8 Marmaton - 6 Other head2right Burbank response of 800-900 boe per day head2right Achieving objective of becoming pure Mid-Continent player • Closed the sale of four of the five divestiture packages for $249.8 million • Redeploying capital for Mid-Continent development

 
Strong Track Record of Growth 6 Production (Boe) / Day EBITDA ($mm) Reserves (Mmboe) $- $50 $100 $150 $200 $250 $300 $350 $400 $450 2009 2010 2011 2012 2013 $224 $288 $313 $337 $389 $ M M 130 135 140 145 150 155 160 165 170 175 2010 2011 2012 2013 149 156 146 158 Overview - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2010 2011 2012 2013 Q2 YTD 2014 11,214 11,701 12,464 13,715 16,259 10,841 9,882 9,032 9,247 9,940 2,129 3,415 3,729 3,911 Oil Gas NGL head2right Core Operating Area – Mid-Continent Region head2right Key Plays – NOMP, Panhandle Marmaton, Woodford and EOR head2right Oil Focused (Reserves – 68% oil / liquids) head2right Strong future growth potential head2right Prudent balance sheet and liquidity head2right Key Growth Drivers • Repeatable Resource Plays • CO2 Enhanced Oil Recovery 22,055 23,713 24,914 26,691 30,110

 
Our Position square4 532,000 net surface acres square4 Portfolio poised to deliver double digit growth square4 Oil-rich portfolio with focus on high return, oil leveraged plays square4 Significant inventory of repeatable drilling opportunities • 23 year drilling life with 10 rigs running square4 Long-term stable oil and cash flow growth from EOR square4 2Q YTD Production – 30.1 mboepd (67% liquids) Midcontinent Focus – The Next Untold Story 7 Source: The Oklahoman

 
Mid-Continent Advantages • Prolific hydrocarbon producing basin • Numerous reservoirs with stacked pay potential for horizontal drilling • Material infrastructure for enhanced execution • Lower historical oil differentials • Industry friendly environment head2right Constructive regulatory environment head2right Potential to increase acreage through pooling Why Mid-Continent – The Next Untold Story 8 lan dm as s Amarillo -Wichita Uplift La nd m as s Sh all ow Se as Sh all ow Se as Ft . W orth Basin Anadarko Basin Midland BasinDelaware Basin

 
Leader Among Mid-Continent Peers in Oil Production 9 Percentage of 2Q 2014 Oil Production $300 0% 10% 20% 30% 40% 50% 60% Chap MPO NFX SD JONE XEC 53% 45% 39% 38% 31% 30% Sources: Company 2nd Quarter filings 2014

 
NOMP Marmaton Core Plays Net Surface Acres: 210,982 Gross Drilling Locations: 2,088 Gross Operated Drilling Locations: 1,123 Net Surface Acres: 128,225 Gross Drilling Locations: 1,124 Gross Operated Drilling Locations: 768 10 Woodford Net Surface Acres: 164,945 Gross Drilling Locations: 2,108 Gross Operated Drilling Locations: 1,033 Cana SCOOP Arkoma Central OK Woodford Meramec NOMP EOR Q1 2014 Net Daily Production (boe/d): 7,408 Total Resource Potential: 193 Mmboe Active Operated Projects: 8 Burbank Area Panhandle Area Central OK Area Marmaton Meramec Shale

 
Stacked High Quality Oil Plays NOMP & Woodford 11 OK TX KS Chaparral Acreage NOMP – 119,224 Prospective Acres Total Stacked Net Acres – 343,319 Acres (1) Much of Chaparral’s Mid-Continent acreage is located within a stacked pay environment Woodford – 118,095 Prospective Acres New Play – 106,000 Prospective Acres (1) Acreage is duplicated for stacked plays

 
Multiple Pay Zones in the Mid-Continent 12 Industry Horizontal Drilling Targets

 
Horizontal Drilling Inventory and Play Resource Potential 13 Oil Rich (2) Gas Rich (2) Total (2) Play Net Acres(1) Gross Locations Resource (mmboe) Net Acres(1) Gross Locations Resource (mmboe) Net Acres(1) Gross Locations Resource (mmboe) NOMP/Meramec Shale 199,569 1,104 60 43,414 984 190 242,983 2,088 250 Panhandle Marmaton 128,225 1,124 88 - - - 128,225 1,124 88 Woodford (Upside) 145,418 1,768 139 19,527 340 108 164,945 2,108 247 New Play 106,168 1,086 80 - - - 106,168 1,086 80 Grand Total 579,380 5,082 367 62,941 1,324 298 642,321 6,406 665 Inventory Life (NOMP and Panhandle Marmaton) Number of Rigs 10 15 20 Inventory Life (Years) 23 15 11 (1) Acreage is duplicated for stacked plays (2) Inclusive of proved reserves

 
Capital Budget ($mm) 14 Component 2011 2012 2013 Q2 YTD 2014 2014 Revised Budget 2014B Allocation % Drilling $172 $239 $269 $189 $396 59% EOR 86 187 $128 $90 $149 22% Enhancements 32 20 $22 $13 $18 3% Acquisitions 17 48 $209 $34 $50 7% Other (P&E, Capitalized G&A, etc) 28 37 $42 $27 $58 9% Total $336 $531 $670 $354 $671 100% Key Drilling Areas Capital (*) Wells NOMP $156 43-47 Panhandle Marmaton 134 30-34 Woodford 20 3-5 Other 86 Total $396 EOR Field Capital N. Burbank $82 Panhandle Area 55 Other 12 Total $149 *Includes both Operated and Non-Operated Wells 2014 Capital Allocation

 
Expected Returns in our Core Areas 15 0% 10% 20% 30% 40% 50% 60% 70% 80% Play IRRs (1) - 5,000 10,000 15,000 20,000 25,000 CXO ATHL CHAP * AR MPO JONE ROSE 22,000 7,725 6,406 5,011 3,300 2,542 1,455 Gross Unrisked Drilling Locations *Chaparral’s Plays in red (1) Selected data from Credit Suisse Research and Analytics using futures strip as of 9/24/2013(2) Management Type Curve Source: Company presentations as of August 2014 * - Horizontal Only

 
Over 1 BBOE - Reserve and Inventory Upside Potential 16 Planned 2014 Divestiture 158 (22) 223 241 81 193 145 1,019 0 200 400 600 800 1000 1200 2013 Proved Reserves Planned Divestiture NOMP/ Meramec Shale Woodford Marmaton EOR Other Total M M b o e

 
NOMP Resource Potential

 
Northern Oklahoma Mississippi Play (NOMP) 18 head2right 242,983 net acres including the Meramec shale head2right Principally carbonate in north, and develops into carbonate/shale sequence as the play moves south head2right Multiple benches with ongoing development head2right Over 250 MMBoe of potential recovery head2right 2,088 (1,123 Operated) un-risked drilling locations (on 3-4 wells per section spacing) head2right Chaparral has drilled/participated in over 120 wells head2right 2014 Operated Expectations: - Run 3-6 rigs (will exit year with 6-8 rigs) - $143 million in capital - 43 – 47 wells Overview NOMP Asset Map OK TX KS Chaparral Acreage

 
NOMP Carbonate Economics 19 • EUR: 352 Mboe • Oil %: 40-50% • D&C cost: $3.3 - $3.7 million Oil • EUR: 154 MBbl • IP (30 Day) 155 BOPD • Initial Decline: 73% • b Factor: 1.5 Wet Gas • EUR: 1,190 MMCF • IP (30 Day) 1,044 MCFD • Initial Decline: 73% • b Factor: 1.5 NGLs(a) • EUR: 60 MBBL • IP (30 Day) 59 BOPD • NGL Yield: 50 BBLS/MMCF • Gas Shrink Factor: 75% Type Curve Parameters (a) After processing shrink 20% 30% 41% 54% 68% 0% 10% 20% 30% 40% 50% 60% 70% 80% $70/ $3.5 $80/ $4 $90/ $4.5 $100/ $5 $110/ $5.5 R O R % Rate of Return versus Wellhead Pricing 0 200 400 600 800 1000 1200 1400 0 50 100 150 200 250 0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 B O P D PRODUCTION DAYS NOMP TYPE CURVES(1) EUR = 352 MBOE OIL BOPD GAS MCFD M CFD % EUR per Yr Yr. 1 – 18% Yr. 2 – 9% Yr. 3 – 6% Yr. 4 – 5% (1) Management Estimate

 
NOMP Well Performance 20 NOMP Well Performance OK TX KS Chaparral Acreage OPERATOR WELL 30 DAY IP CHAPARRAL GLADYS 3H-25 1,292 BOEPD CHAPARRAL KUDU 1H-21 513 BOEPD CHAPARRAL CENTIPEDE 1H-15 876 BOEPD CHAPARRAL LEE 1MH-1 711 BOEPD CHAPARRAL DOLEZAL 1H-15 185 MBO (1) CHAPARRAL SALT CREEK 1H-10 126 BOEPD CHAPARRAL DU CARDINAL 1MH-27 1,076 BOEPD B&W BODE 1-2H 471 BOEPD ARP SALUKI 2-4H 683 BOEPD LONGFELLOW HLADIK 15-M4H 1,884 BOEPD NEWFIELD KRETCHMAR 1H-2W 772 BOEPD MIDSTATES LONGHURST 3H-34 2,559 BOEPD NEWFIELD YOST 1H-18X 854 BOEPD 12 3 4 9 8 5 6 10 11 12 13 1 2 3 4 5 6 7 8 9 10 11 12 13 7 MeramecMeramec Shale (1) Represents cumulative production from unstimulated well drilled in 2001 and 2,200’ lateral

 
0 50 100 150 200 250 300 350 400 450 Average - 15 Wells 393 3 0 D a y I P R a t e ( B O E P D ) 0 2 4 6 8 10 12 < 200 200 - 350 350 - 500 500 - 800 800 + 3 6 6 7 6 2 3 4 5 1 N u m b e r o f W e l l s 2013 2014 YTD 5 NOMP 2013 and 2014 YTD Results 21 Type Curve: 241 12 9 10 7 30 – Day IP Rate (BOEPD) 2013 – 28 wells 2014 YTD – 15 wells

 
Improved NOMP Execution 22 0 10 20 30 40 50 60 70 80 Q2 2012 Q3 2012 Q4 2012 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 41 34 26 21 21 20 22 21 25 39 26 24 28 21 20 16 28 16 79 59 49 49 42 40 38 49 41 D a y s Spud to Rig Release Rig Release to First Production

 
NOMP Growth 23 Production (Boe) / Day Net Acres* - 50 100 150 200 250 300 2012 2013 Q2 2014 175 210 248 N e t A c r e s ( 0 0 0 ) - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2012 2013 2014 YTD 787 2,150 2,953 576 1,715 3,732 B o e / D a y Liquids Gas 6,685 3,865 1,363 * Totals include Meramec Acreage

 
Marmaton Resource Potential

 
OK TX KS Marmaton Play 25 head2right The Marmaton Play is another key oil resource consisting of multiple carbonate benches with ongoing development head2right Largest operator in play head2right 128,225 net acres head2right 1,124 (768 Operated) unrisked drilling locations head2right Over 88 MMBoe of potential recovery head2right Chaparral has drilled/participated in 46 wells and also acquired 68 wells from Cabot head2right 2014 Operated Expectations: - Run 1-3 rigs - $132 million in capital - 30 - 34 wells Overview Marmaton Asset Map Chaparral Acreage HANSFORD LIPSCOMB OCHILTREE TEXAS ELLIS BEAVER

 
Marmaton Economics 26 Type Curve Parameters • EUR: 143 Mboe • Liquids 93% / Oil %: 80% • D&C cost: $3.0 - $3.4 million Oil • EUR: 115 MBbl • IP (30 Day) 201 BOPD • Initial Decline: 82% • b Factor: 1.146 Wet Gas • EUR: 102 MMCF • IP (30 Day) 178 MCFD • Initial Decline: 82% • b Factor: 1.146 NGLs(a) • EUR: 18 MBBL • IP (30 Day) 22 BOPD • NGL Yield: 179 BBLS/MMCF • Gas Shrink Factor: 59% (a) After processing shrink 11% 19% 28% 38% 49% 0% 10% 20% 30% 40% 50% 60% $70 / $3.5 $80 / $4 $90 /$ 4.5 $100 / $5 $110 / $5.5 R O R % Rate of Return versus Wellhead Pricing (1) Management Estimate 0 50 100 150 200 250 0 50 100 150 200 250 300 0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 B O P D PRODUCTION DAYS Panhandle Marmaton TYPE CURVES(1) EUR = 143 MBOE OIL BOPD GAS MCFD M CFD % EUR per Yr Yr. 1 – 24% Yr. 2 – 12% Yr. 3 – 7% Yr. 4 – 5%

 
HANSFORD LIPSCOMB OCHILTREE TEXAS ELLIS BEAVER Panhandle Marmaton Well Performance 27 Panhandle Marmaton Well Performance Chaparral Acreage OK TX KS OPERATOR WELL 30 DAY IP CHAPARRAL NORA 49-1H 427 BOEPD CHAPARRAL THOMAS 1HX-35 922 BOEPD CHAPARRAL 4 RED CATTLE 1-23H 622 BOEPD CHAPARRAL KILE 1-7H 1414 BOEPD CHAPARRAL LOWERY 2H-14 479 BOEPD UNIT PRICE TRUST 1-28H 886 BOEPD UNIT GIFT 1-27H 672 BOEPD UNIT FISH 1H 466 BOEPD UNIT STATE OF OK A 1-6H 599 BOEPD UNIT SIMPSON 1-7H 543 BOEPD TEXAS AMER. CONNER UT 101H 300 BOEPD TEXAS AMER. FRIESEN-JOHNSON 171 BOEPD 1 2 3 4 8 7 5 9 10 1112 6 6

 
Woodford Shale Play

 
Woodford Shale Play 29 head2right The Woodford Shale Play is a material resource play and provides significant upside head2right The Woodford Shale Play consists of well defined productive regions head2right 164,945 net acres head2right Over 200 MMBoe of potential recovery head2right 2,108 (1,033 Operated) unrisked drilling locations head2right Chaparral has drilled/participated in 50 wells head2right 2014 Expectations: - $20 million in capital (1) - 3 - 5 wells (1) Includes approximately $4M of completion capital from 2013 drilling program Overview Woodford Asset Map Chaparral Acreage CANA SCOOP ARKOMA CENTRAL OK TX KS

 
0 100 200 300 400 500 600 700 0 20 40 60 80 100 120 140 160 180 200 0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 B O P D PRODUCTION DAYS Central Woodford TYPE CURVES(1) EUR = 246 MBOE OIL BOPD GAS MCFD M CFD Central Woodford Economics 30 Type Curve Parameters • EUR: 246 Mboe • Oil %: 60-70% • D&C cost: $3.2 - $3.7 million Oil • EUR: 150 MBbl • IP (30 Day) 168 BOPD • Initial Decline: 74% • b Factor: 1.4 Wet Gas • EUR: 523 MMCF • IP (30 Day) 585 MCFD • Initial Decline: 74% • b Factor: 1.5 NGLs(a) • EUR: 26 MBBL • IP (30 Day) 29 BOPD • NGL Yield: 50 BBLS/MMCF • Gas Shrink Factor: 80% (a) After processing shrink 22% 29% 38% 48% 58% 0% 10% 20% 30% 40% 50% 60% 70% $70 / $3.5 $80 / $4 $90 /$ 4.5 $100 / $5 $110 / $5.5 R O R % Rate of Return versus Wellhead Pricing (1) Management Estimate % EUR per Yr Yr. 1 – 16% Yr. 2 – 10% Yr. 3 – 7% Yr. 4 – 5%

 
Woodford Well Performance 31 OK TX KS Chaparral Acreage Woodford Well Performance CANA SCOOP ARKOMA CENTRAL 1 2 3 4 5 6 7 8 9 10 11 OPERATOR WELL BEST 30 DAY IP DEVON ROTHER 1-24H 1,404 BOEPD DEVON BESSIE 6-2H 863 BOEPD CIMAREX DRAPER 1-25H 3,228 BOEPD NEWFIELD/DCP KLADE 1H-3X 476 BOEPD CONTINENTAL MILLS 1-21H 872 BOEPD CONTINENTAL LYLE 1-30H 1,294 BOEPD DEVON LECK 1-16H 1,154 BOEPD DEVON THOMAS 1-8WH 260 BOEPD DEVON WINNEY 1-5H 432 BOEPD PLYMOUTH MARCELLA 1-36H 730 BOEPD PLYMOUTH THOMPSON 2-6H 415 BOEPD DEVON WALKING WOMAN - 8 Wells in 2014 1,116 BOEPD (AVG) 1 2 3 4 5 6 7 8 9 10 11 1 2 3 4 5 6 7 8 9 10 11 12 12

 
CO2 EOR is a Major Part of Chaparral’s Growth Story

 
Leader in the CO2 EOR Industry 33 Chaparral is the third-most active CO2-EOR operator in the U.S. Source: Modified after Apr’14 Oil & Gas Journal Survey of Operators 3 32 # of Active Producer CO2-EOR Projects 33 25 7 6 5 4 4 3 3 Total 136 Others 3 8

 
CO2 EOR Focused Areas 34 head2right CO2 Project Inventory square4 10 units with proved reserves square4 40 units with 1P, 2P & 3P EOR reserves head2right CO2 Infrastructure – 473 Miles head2right 85 MMscf/D of existing CO2 supply head2right 2014 Expectations: square4 $149 million in capital square4 Increase in net uplift by 1,500 boepd head2right Expect CO2 EOR Business Unit to be cash flow positive in 2015 and beyond Overview Total OOIP 3,041 MMBo Primary Production 533 MMBo Secondary Recovery 449 MMBo Tertiary Potential 364 MMBo Net Tertiary Potential 213 MMBo Chaparral EOR Fields Chaparral CO2 Pipelines Third Party CO2 Pipelines CO2 Source LocationsFL0022h Panhandle Area Burbank Area Central Oklahoma Area

 
Proven Track Record of CO2 EOR Performance 35 Field CO2 Initiation Net Production prior to Injection (Bopd) July 2014 Net Production (Bopd) Gross Uplift Estimated Ultimate Recovery (Mmboe) Panhandle Area Camrick 2001 103 1,683 8.0 North Perryton 2006 21 731 3.4 Booker 2009 9 1,132 2.0 Farnsworth 2010 139 1,628 7.5 Central Oklahoma NW Velma Hoxbar 2010 78 400 1.2 Burbank Area Burbank 2013 1,372 1,823 88.3

 
Total EOR Uplift Growth 36 - 1,000 2,000 3,000 4,000 2011 2012 2013 Q1 2014 Q2 2014 1,217 1,994 2,560 2,961 3,298 B O E / D a y

 
North Burbank CO2 EOR Development

 
Burbank Area Overview 38 head2right Chaparral’s North Burbank unit is its largest EOR field square4 CO2 injection started in June 2013 square4 Oklahoma’s largest unit with over 820 Mmbo OOIP and 320Mmbo cumulative production to date head2right 2014 Expectations: square4 2,500 Gross Boepd EOR Exit Rate square4 $82 million in capital - Drill 20 wells - 120 workovers - Phase 2 facility expansion North Burbank Overview Burbank Area Asset Map Total OOIP 1,163 MMBbls Primary Production 239 MMBbls Secondary Recovery 211 MMBbls Tertiary Potential 119 MMBbls Net Tertiary Potential 100 MMBbls head2right Anthropogenic CO2 from fertilizer plant head2right 68.3 miles of 8” pipeline head2right 19,500 HP compression facility head2right Commenced CO2 injection in June 2013 with current rate at 45 mmcfpd Coffeyville CO2 System

 
100 1,000 10,000 100,000 1,000,000 100 1,000 10,000 100,000 1,000,000 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020 2030 G r o s s B o e / D Primary Development Secondary Development Tertiary Development North Burbank CO2-EOR Flood 39 +14000 “Waterflood” “CO2 EOR”

 
North Burbank Unit – Gross Production 40 +1400 “CO2 EOR”

 
Financial Overview

 
Financial Metrics per BOE 42 Production (Boe) / Day LOE / Boe EBITDA / BoeG&A / Boe - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2011 2012 2013 Q2 YTD 2014 B* 11,701 12,464 13,715 16,259 17,429 9,882 9,032 9,247 9,940 8,499 2,129 3,415 3,729 3,911 3,570 B o e / d a y Liquids Gas NGL 23,713 24,914 26,691 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 2011 2012 2013 Q2 YTD 2014 B* $14.03 $14.36 $14.35 $13.13 $13.00 $ / B O E $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2011 2012 2013 Q2 YTD 2014 B* $4.86 $5.46 $5.53 $5.21 $5.25 $ / B O E $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 2010 2011 2012 2013 Q2 YTD $35.56 $35.98 $37.03 $39.93 $42.49 $ / B O E 30,110 29,500 *2014 B based on Midpoint of guidance

 
Hedge Portfolio 43Note: Dollars represent average strike price of hedges (includes all derivative instruments) Weighted Average Price 2014 2015 2016 Oil $95.91 $93.20 $92.89 Gas $4.03 $4.20 $4.33 Percentage of 2Q – 4Q14E Production Hedged 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% CHAP NFX SD JONE MPO XEC 96% 73% 68% 64% 64% 25% Approximate Percentage of 2015E Production Hedged 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% CHAP NFX JONE MPO SD XEC 84% 50% 42% 41% 32% Source: Barclay’s Research – Oil and Gas Update 6/6/14 and company presentations % of Total Proved Reserves Hedged (as of Aug 4, 2014)

 
Financial Flexibility to Execute Strategy 44 Net Debt / EBITDA Liquidity ($mm) $325 $300 $400 0 100 200 300 400 500 600 2013 2016 2017 2018 2019 2020 2021 2022 $232 $300 $400 $550 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x 4.5x 5.0x 2009 2010 2011 2012 2013 Q2 YTD 4.9x 3.2x 3.3x 3.9x 3.5x 3.5x $- $100 $200 $300 $400 $500 $600 2009 2010 2011 2012 2013 Q2 2014 $77 $429 $407 $504 $376 $319 square4 No senior note maturities before 2020 square4 Hedge positions in place to secure cash flow in near term Current Maturity Profile ($mm)

 
2014 Guidance 45 Operating Statistics 2014 Guidance Capital Expenditures ($MM) $656 - $683 Production (MMBoe) 10.6 – 11.0 General and Administrative $5.00 - $5.50/Boe Lease Operating Expense $12.75 -$13.25/Boe

 
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