8-K

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): June 4, 2013

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 June 4, 2013, 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 RBC Capital Markets’ Global Energy and Power Conference in New York, New York.

Note Regarding Non-GAAP Financial Measures

The investor presentation attached as an exhibit hereto contains certain references to adjusted EBITDA and PV-10 value, which are non-GAAP financial measures, 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. We consider compliance with this covenant to be material. 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 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.

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, in accordance with the terms of our prior credit facility. In July 2010, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to (1) permit cash proceeds received from the monetization of derivatives to be included in the calculation of Consolidated EBITDAX, to the extent that such monetizations, in any period between scheduled redeterminations, do not exceed 5% of the borrowing base then in effect, and (2) permit the exclusion from the calculation of Consolidated EBITDAX of up to $4.5 million in one-time cash expenses associated with our financing transactions that were incurred and paid during the second quarter of 2010. As a result, beginning with the second quarter of 2010, we have changed our calculation of adjusted EBITDA to include cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization, to the extent permitted by our senior secured revolving credit facility. However, we have not changed our calculation of adjusted EBITDA to exclude approximately $2.3 million of one-time cash expenses associated with our financing transactions. As a result of the permitted exclusion of these expenses, our Consolidated EBITDAX as calculated for covenant compliance purposes is higher than our adjusted EBITDA for the year ended December 31, 2010.

In April 2011, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

In May 2012, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.875% Senior Notes due 2017 from the calculation of Consolidated EBITDAX.

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

	Three months ended March 31,						Year ended December 31,
(in thousands)	2013			2012			2012			2011			2010
Net (loss) income	$	(1,190	)	$	9,782		$	64,403		$	42,048		$	33,713
Interest expense	24,291			24,156			98,402			96,720			81,370
Income tax (benefit) expense	(687		)	6,196			37,837			35,924			23,803
Depreciation, depletion, and amortization	43,916			36,932			169,307			146,083			109,503
Unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments	(10,003		)	(12,423		)	(46,746		)	27,452			23,889
Non-cash change in fair value of non-hedge derivative instruments	25,442			12,720			(12,411		)	(57,899		)	(2,523		)
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date included in EBITDA	—			—			—			—			9,418
Interest income	(96		)	(58		)	(225		)	(165		)	(144		)
Stock-based compensation expense	1,314			1,151			3,065			3,747			2,600
(Gain) loss on sale of assets	(95		)	95			(149		)	(1,284		)	(184		)
Loss on extinguishment of debt	—			—			21,714			20,592			2,241
Loss on impairment of oil and natural gas properties	—			—			—			—			—
Other non-cash charges	—			—			2,000			—			4,150
Adjusted EBITDA	$	82,892		$	78,551		$	337,197		$	313,218		$	287,836

PV-10 value

PV-10 value is a non-GAAP measure that differs from the standardized measure of discounted future net cash flows in that PV-10 value is a pre-tax number, while the standardized measure of discounted future net cash flows is an after-tax number. We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows for the periods shown:

	As of December 31,
(in thousands)	2012			2011			2010
PV-10 value	$	2,068,620		$	2,309,089		$	1,770,061
Present value of future income tax discounted at 10%	(544,939		)	(711,177		)	(534,035		)
Standardized measure of discounted future net cash flows	$	1,523,681		$	1,597,912		$	1,236,026

Item 9.01. Financial Statements and Exhibits

(d) Exhibits.

Exhibit Number	Description
99.1	Investor Presentation

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.

June 4, 2013	CHAPARRAL ENERGY, INC.
	By:	/s/    JOSEPH O. EVANS
	Name:	Joseph O. Evans
	Title:	Chief Financial Officer and Executive Vice President

Exhibit Index

Exhibit Number	Description
99.1	Investor Presentation

EX-99.1

Chaparral Energy Royal Bank of Canada Finance Conference June, 2013

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. 2

3 Company Representatives Joe Evans Chief Financial Officer & Executive Vice President Mark Fischer Chief Executive Officer & President Melinda Conner Corporate Finance Manager

Chaparral Overview  Founded in 1988, Based in Oklahoma City  Core areas — Mid-Continent (Oklahoma) and Permian Basin (W. Texas)  Stable 1P base with large potential upside – 727 MMBoe, R/P 16 years  Oil focused:  Third largest “oil” producer in Oklahoma  (71% oil; 29% gas) – 2012 SEC Reserves  (64% oil; 36% gas) – 2013 Production Estimate  Growth drivers:  Near-term growth potential through drilling ~ 350,000 acres  Long-term growth through CO2 EOR – 70 fields Company Statistics 2011 2012 Q1, 2013 Average Production (Boe/d) ~23,700 ~24,910 ~24,930 SEC Proved Reserves (MMBoe) 156.3 146.1 NA SEC Proved Reserves PV-10 ($ in mm) $2,309 $2,069 NA TTM EBITDA ($ mm) $313 $337 $342 4

Operating Areas As of December 31, 2012 (SEC) Core Area Growth Area Acreage Field Offices Headquarters North Texas Reserves: 3.8 MMBoe, 3% of total Production: 0.4 Mboe/d, 2% of total Permian Basin Reserves: 17.1 MMBoe, 12% of total Production: 3.2 MBoe/d, 13% of total Company Total December 2012 proved reserves – 146.1 MMBoe 2012 average daily production – 24.9 MBoe/d Acreage (gross / net): 1,238,747 / 628,564 Val Verde Basin Sabine Uplift Midland Basin Delaware Basin Ouachita Uplift Arkoma Basin Fort Worth Basin Anadarko Woodford Basin OKC Gulf Coast Reserves: 2.0 MMBoe, 1% of total Production: 0.8 MBoe/d, 3% of total Mid-Continent (Anadarko Basin & Central Oklahoma) Reserves: 117.8 MMBoe, 81% of total Production: 19.3 MBoe/d, 78% of total Ark-La-Tex Reserves: 5.4 MMBoe, 4% of total Production: 1.2 MBoe/d, 5% of total 5

Strong Record of Reserve and Production Growth Year-End SEC Reserves (MMBoe) (1) 2003 – 2012 CAGR = 12% Annual Production (MMBoe) 2003 – 2012 CAGR = 15% Chaparral’s reserve replacement ratio averaged 383% per year since 2003 6 Year Oil Gas 2007 $96.01 $6.80 2008 $44.60 $5.62 2009 $61.18 $3.87 2010 $79.43 $4.38 2011 $96.19 $4.11 2012 $94.71 $2.76 1) Reserves as of December 31 for each year calculated using flat SEC pricing per the following: 0 20 40 60 80 100 120 140 160 180 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 51 73 103 151 164 113 142 149 156 146 0 1 2 3 4 5 6 7 8 9 10 2.6 3.2 4.2 5.4 6.8 7.1 7.6 8.1 8.7 9.1 9.6-9.8 *2013B illustrated at midpoint of guidance

2011 to 2012 SEC Reserves Reconciliation 7 Total YTD Proved Volume Reconciliation Volumes in MMBOE Beginning Balance (12/31/2011) 156.3 2012 Production -9.1 Extensions & Discoveries 13.3 Improved Recoveries (EOR) 0.8 Divestitures -3.8 Pricing Revisions -12.0 Other Revisions 0.5 Ending Balance (12/31/2012) 146.1 Negative price revisions due to low natural gas pricing and divestitures reduced year end reserves by ~15.8 mmboe or 11% Product Pricing - SEC 12/31/2011 Price 12/31/2012 Price Difference Difference (%) Oil ($/bbl) 96.19 94.71 -1.48 -1.5% Gas ($/MMBtu) 4.11 2.76 -1.35 -32.8

Current Production Production by Quarter 8 23,278 23,018 26,098 27,223 24,928 - 5,000 10,000 15,000 20,000 25,000 30,000 Q1,2012 Q2,2012 Q3,2012 Q4,2012 Q1,2013 BO E P D Production in the 1th quarter of 2013 decreased 10% over the previous quarter and increased 6% when compared to the 1th Quarter 2012  From 2011 to 2012, estimated liquids production increased by over 15% and gas production declined by approximately 8%  Production results reflect the impact of reduced 4th quarter rig count due to front-end loading of capital budgets in 2011 and 2012

Net Debt / EBITDA Liquidity ($mm) Financial Position to Execute Strategy $325 $300 $400 $69 $300 $400 $550 2012 2016 2017 2018 2019 2020 2021 2022 Current Maturity Profile ($mm) 5.6x 4.4x 4.9x 3.2x 3.3x 3.9x 3.9x 2.3x 2.0x 2.0x 0.0x 0.0x 0.1x 0.1x 2007 2008 2009 2010 2011 2012 Q1 2013 Total net debt to EBITDA Net secured debt to EBITDA 9 $88 $55 $77 $429 $407 $505 $458* 2007 2008 2009 2010 2011 2012 Q1 2013  Strong Financial Position  No senior note maturities before 2020  Hedge positions in place to secure cash flow in near term *Subject to 4.5x Debt / EBITDA covenant. Maximum availability at 3/31/13 was $210mm.

Capital Budget ($mm) Component 2010 2011 2012 2013B 2013B Allocation% Drilling $196 $172 $239 $206 50% EOR 36 86 187 $130 32% Enhancements 39 32 20 $20 5% Acquisitions 41 17 48 $25 6% Other (P&E, Capitalized G&A, etc) 32 28 37 $30 7% Total $344 $336 $531 $411 100% Key Drilling Areas Capital Wells Northern OK Mississippi Horizontal $107 38 Marmaton 40 11 Anadarko Cleveland Sand 20 7 Anadarko Granite Wash 7 3 Other 32 * Total $206 59 10 EOR Field Capital N. Burbank $84 Panhandle Area 42 Other 4 Total $130 99% of 2013 Capital Program is Oil Focused *Includes both Operated and Non-Operated Wells

11 Drilling Resource Potential

Substantial Resource Potential 12  Near-Term  1,697 Unrisked (1,116 Risked) Net Undrilled Wells  146 MMBoe Proved Reserves Plus 581 MMBoe Unproved Resource Potential  Conventional Drilling (ROR 50% - 75%)  Anadarko Granite Wash  Anadarko Cleveland Sand  Unconventional Resource Play Drilling (ROR 25% - 75%)  Northern Oklahoma Mississippi Play (NOMP) ~ 128,000 acres  Panhandle Marmaton ~ 50,000 acres  Anadarko Woodford Shale ~ 22,000 acres  Bone Spring/Avalon Shale ~ 18,000 acres  Long-Term  CO2 EOR – 70 fields, 200+ MMBO (ROR 25% - 40%)

Northern Oklahoma Mississippi Play  The Northern Oklahoma Mississippi Play (“NOMP”) is a key near–term focus area for Chaparral  Chaparral acreage over 128,000 net acres in the NOMP  Over 107 MMBoe of potential  800 unrisked drilling well inventory Chaparral Acreage 13 Overview NOMP Asset Map NOMP Well Economics IP Rates: 300 – 600 Boe/d EUR: 300 – 400 MBoe Well Cost: $3.3 – $4.0 million % Oil 40% – 50% IRR: 25% – 60%

NOMP Play Map 14

15 West Noble Area: ~20,500 Net Acres  Recent NOMP Acquisition – 14,500 Acres

NOMP Economics • EUR : 352 Mboe • Oil and NGL %: 40-50% • Well cost: $3.3 - $4.0 million Oil • EUR: 154 MBbl • IP (30 Day) 155 BOPD • Initial Decline: 73% • b Factor: 1.5 Gas • EUR: 1,190 MMCF • IP (30 Day) 1,044 MCFD • Initial Decline: 73% • b Factor: 1.5 NGLs(a) • EUR: 67 MBBL • IP (30 Day) 59 BOPD • NGL Yield: 56.3 BBLS/MMCF • Gas Shrink Factor: 72% Type Curve Parameters (a) After processing shrink 16% 21% 29% 38% 47% 58% 0% 10% 20% 30% 40% 50% 60% 70% $60/ $3 $70/ $3.5 $80/ $4 $90/ $4.5 $100/ $5 $110/ $5.5 R O R % Rate of Return versus Wellhead Pricing 16 0 200 400 600 800 1000 1200 1400 0 50 100 150 200 250 0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 B OPD PRODUCTION MONTHS NOMP TYPE CURVES EUR = 352 MBOE OIL BOPD GAS MCFD 6% 4% M C F D 18% 9% 5% % EUR per Year

17 NOMP CORE BOEPD – ALL INTEREST MISS-HZ NORMALIZED AVERAGE VS 352 MBOE TYPE CURVE

Marmaton Shelf Play 18 Lamaster 2H-23 Peak Rate: 579 Boepd Johnston 1H-24 Peak Rate: 606 Boepd Jay 1H-1098 Peak Rate: 265 Boepd Lamaster 1H-23 Peak Rate: 769 Boepd Marmaton Well Economics IP Rates: 150 – 600 Boe/d EUR: 150 – 200 Mboe Well Cost: $3.5 – $4.0 million % Oil 90% IRR: 25% – 70% Chaparral Acreage Marmaton Wells

Marmaton Shelf Activity 19 Chaparral Acreage Marmaton Vertical Wells 2013 Horizontal Wells Current Chaparral Rigs

Marmaton Shelf Economics Type Curve Parameters • EUR : 168 Mboe • Oil and NGL %: 90% • Well cost: $3.5 - $4.0 million Oil • EUR: 157 MBbl • IP (30 Day) 285 BOPD • Initial Decline: 99.7% • b Factor: 1.18 Gas • EUR: 65MMCF • IP (30 Day) 124 MCFD • Initial Decline: 99.7% • b Factor: 1.18 NGLs(a) • EUR: 13 MBBL • IP (30 Day) 29 BOPD • NGL Yield: 195 BBLS/MMCF • Gas Shrink Factor: 60% (a) After processing shrink 14% 29% 45% 69% 93% 138% 0% 20% 40% 60% 80% 100% 120% 140% 160% $60 /$2.5 $70 / $3 $80 / $3.5 $90 /$ 4 $100 / $4.5 $110 / $5 R O R % Rate of Return versus Wellhead Pricing 20 0 20 40 60 80 100 120 140 0 50 100 150 200 250 300 350 400 0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 B OPD PRODUCTION MONTHS MARMATON TYPE CURVES EUR = 168 MBOE OIL BOPD GAS MCFD M C F D 7% 4% 29% 11% 5% % EUR per Year

Marmaton Shelf Results 21

22 Chaparral: A Growing Mid-Continent CO2 EOR Company

# of Active Producer CO2-EOR Projects 31 22 8 7 7 7 6 5 4 4 4 Total 105 Source: April 2012 Oil & Gas Journal Note: Chaparral projects include the North Burbank Unit 23 Chaparral is a Leader in the CO2-EOR Industry Chaparral is the third most active CO2-EOR producer in the U.S.

CO2 EOR Focused Areas 24  CO2 Project Inventory  70 units with 1P, 2P & 3P EOR reserves  9 units with proved reserves  9 units with CO2 injection  CO2 Infrastructure – 473 Miles  318 miles of active line  68 miles under construction  87 miles of inactive line  CO2 Supply  47 MMscf/D of existing CO2 supply  43 MMscf/D new CO2 supply CO2 Tertiary Recovery Projects Panhandle Area Permian Basin Central Oklahoma Area Burbank Area

Coffeyville Fertilizer Plant Koch Fertilizer Plant Arkalon Ethanol Plant Agrium Fertilizer Plant 25 Current CO2 Infrastructure/Future EOR Potential Total OOIP 3,735 MMBo Primary Production 628 MMBo Secondary Recovery 597 MMBo Tertiary Potential 410 MMBo Net Tertiary Potential 197 MMBo Active CO2 fields CO2 fields in 5 year plan Chaparral Owned Potential CO2 fields CO2 Source Locations Chaparral CO2 Pipelines Third Party CO2 Pipelines

EOR 2013 Capital Budget(1) 26 Budget by Category ($mm) 2012 2013B Infrastructure / Pipelines 105 62 Drilling 20 16 Enhancements / CO2 Purchases 62 52 Total $187 $130  Burbank Area  North Burbank Unit $84  Panhandle Area  Farnsworth Unit $21  Booker Area 9  Camrick Area 9  NE Hardesty (Non-op) 3 $42  Central Oklahoma  NW Velma Hoxbar $4  Permian  No planned expenditures - $130 2013 Field Projects ($mm) Panhandle Area Permian Basin Central Oklahoma Area Burbank Area (1) Does not include Capitalized G&A

“Enhanced Oil Recovery” – Active Projects* 27 * NBU included in base beginning October 2013; no EOR expected until Q4’13. Initial NBU Added

Chaparral – Potential EOR Production Growth 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 2010 2015 2020 2025 2030 2035 2040 Net Oil Production 28 Additional production from non Business Plan projects meeting corporate economic hurdles Additional CO2 Plan w/ +100 mmcfpd in 2015 at Burbank Business Plan w/ 95 mmcfpd in 2015 Business Plan Add C02 Others

29 North Burbank CO2 Development

North Burbank Unit – Overview  Chaparral’s North Burbank Unit is its largest EOR field and CO2 injection into the North Burbank Unit started in June 2013  Chaparral anticipates that it will spend $800 million associated with this EOR project throughout the life of the field 30 Burbank Area: Net Potential: 100 MMBoe, 51% of total Total OOIP 1,163 MMBbls Primary Production 239 MMBbls Secondary Recovery 211 MMBbls Tertiary Potential 119 MMBbls Net Tertiary Potential 100 MMBbls

31 Burbank in Perspective Secondary Development Primary Development Ne t B O P D Tertiary Development “Waterflood” +12000 BOPD “CO2 EOR”

32 May 2012 Average pressure 1405 psia Ph-I Vicinity North Burbank Unit – Achieved Miscibility Pressure in Phase 1 June 2012 1438 Jul 1461 August 2012 1492 September 2012 1553 October 2012 161 November 162 psia December 1650 February 2013 1704 March 2013 1736 April 3 174

Coffeyville CO2 System 33  The Coffeyville CO2 System  $110 million of total capital expenditures  23,500 HP compression facility  68.3-mile 8-inch pipeline with potential capacity of approximately 60 MMcf/d.  CO2 is sourced from the CVR Partners fertilizer plant in Coffeyville, KS.  Commenced CO2 injection in June 2013 Oklahoma Kansas Coffeyville CO2 System Asset Map Panhandle CO2 System Coffeyville CO2 System

34 COFFEYVILLE CO2 PLANT – PHASE 1 COMPLETE

35 COFFEYVILLE CO2 PLANT

36 COFFEYVILLE CO2 PLANT

37 COFFEYVILLE CO2 PLANT

38 COFFEYVILLE CO2 PIPELINE: TRENCHING RIGHT OF WAY Digging the trench in preparation for laying the pipeline ~68 miles; Coffeyville, KS to Shidler, OK

Operating Team - Injection into North Burbank – June 2013 39

40 Other CO2 Injection Projects

G ro ss B o e /d G ro ss C O 2 P u rc h ases, M c f/ d Secondary Development Primary Development Tertiary Development Camrick CO2–EOR Flood 41 +1500 BOPD

42 North Perryton CO2–EOR Flood G ro ss B o e /d G ro ss C O 2 P u rc h ases, M c f/ d Secondary Development Primary Development Tertiary Development +600 BOPD

43 Primary Development Secondary Development Tertiary Development Booker Area CO2–EOR Flood G ro ss B o e /d G ro ss C O 2 P u rc h ases, M c f/ d +1100 BOPD

44 Primary Development Tertiary Development Secondary Development Farnsworth Area CO2–EOR Flood (West Side Only) Gr o ss B o e /d G ro ss C O 2 P u rc h ases, M c f/ d +2900 BOPD

45 Potential in Excess of 727 MMBoe  Near-term + Long-term strategy yields significant value increase  ~ 70% Oil  Near-term focus on NOMP  De-risk play, unlock value  Production growth  Long-term focus on EOR  Low-risk production upside  Long-life, stable production * Woodford, Bone Spring, Avalon, Cleveland Sand, and Granite Wash (1) 727 136 200 138 107 146 0 100 200 300 400 500 600 700 800 2012 Proved Reserves +NOMP and Marmaton Drilling Potential +EOR Potential + Developing Emerging Plays* +Other Drilling =Total Potential

Financial Overview 46

47 Financial Summary 2010 2011 2012 1Q, 2013 Price Oil & NGL – Wellhead ($/Bbl) $74.53 $87.52 $78.65 $78.16 Gas – Wellhead ($/Mcf) $4.36 $4.08 $2.64 $3.14 Production (MMBoe) 8.1 8.7 9.1 2.2 Oil & NGL (MMBbls) 4.0 5.0 5.8 1.4 Gas (Bcf) 23.7 21.6 19.8 4.8 Financial Data ($mm) Operating Expenses: Lease Operating Expenses $106.1 $121.4 $131.0 $34.0 Production and Ad Valorem Taxes 26.5 34.3 32.0 7.9 General and Administrative Expenses (excludes noncash deferred comp) 27.3 38.3 46.7 12.7 Interest Expense $81.4 $96.7 $98.4 $24.3 EBITDA $288 $313 $337 $83 Total Capital Expenditures $344 $336 $531 $129

Financial Metrics per Boe Production (Boe) / Day LOE / Boe EBITDA / Boe G&A / Boe 48 20,926 22,055 23,712 24,912 24,928 0 10,000 20,000 30,000 2009 2010 2011 2012 1Q, 2013 $12.32 $13.18 $14.03 $14.37 $15.15 $0 $5 $10 $15 $20 2009 2010 2011 2012 1Q,2013 $3.11 $3.72 $4.86 $5.46 $6.25 $0 $2 $4 $6 $8 2009 2010 2011 2012 1Q,2013 $29.47 $35.56 $35.98 $37.03 $37.73 $0 $10 $20 $30 $40 2009 2010 2011 2012 1Q, 2013

Operating Statistics 2013 Guidance Capital Expenditures $410 - $420 million Production 9.6 - 9.8 MMBoe General and Administrative $5.50 - $6.00/Boe Lease Operating Expense $14.25 - $14.75/Boe 2013 Guidance 49

50 Hedge Portfolio : % of TP Reserves (As of June 3, 2013) Note: Dollars represent average strike price of hedges (includes all derivative instruments) Gas Basis Hedges YR Price % TP ’13 $ 0.20 78% ’14 $ 0.22 68%

Question & Answer 51