PDC Energy (PDCE) DEFA14A Additional proxy soliciting materials

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(a) of
the Securities Exchange Act of 1934 (Amendment No.     )

Filed by the Registrant  x
Filed by a Party other than the Registrant  o
Check the appropriate box:
o	Preliminary Proxy Statement
o	Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2))
o	Definitive Proxy Statement
o	Definitive Additional Materials
x	Soliciting Material under §240.14a-12
PDC ENERGY, INC.
(Name of Registrant as Specified In Its Charter)
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
Payment of Filing Fee (Check the appropriate box):
x	No fee required.
o	Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.
	(1)		Title of each class of securities to which transaction applies:
	(2)		Aggregate number of securities to which transaction applies:
	(3)		Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined):
	(4)		Proposed maximum aggregate value of transaction:
	(5)		Total fee paid:
o	Fee paid previously with preliminary materials.
o	Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.
	(1)	Amount Previously Paid:
	(2)	Form, Schedule or Registration Statement No.:
	(3)	Filing Party:
	(4)	Date Filed:

The following presentation was posted on the corporate website of PDC Energy, Inc. on March 25, 2019.

HOWARD WEIL ENERGY CONFERENCE March 26, 2019

Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this presentation are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed, and that cash flows from operations will exceed expected capital investments in crude oil and natural gas properties for 2019 and 2020; management of lease expiration issues and financial ratios relating to our revolving credit facility; midstream capacity and related curtailments; number of wells spud and TIL’d; average percentage working interest of wells; well costs; and average lateral lengths. This presentation contains certain non-GAAP financial measures. A reconciliation of each such measure to the most comparable GAAP measure is presented in the Appendix hereto. We use "adjusted cash flows from operations," "adjusted net income (loss)," "adjusted EBITDA“, and “adjusted EBITDAX” and "PV-10," non-GAAP financial measures, for internal reporting and providing guidance on future results. These measures are not measures of financial performance under GAAP. We strongly advise investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure. See the Appendix for a reconciliation of these measures to GAAP. Rate of return estimates do not reflect lease acquisition costs or corporate general and administrative expenses. Non-proved estimates of potentially recoverable hydrocarbons and EURs may not correspond to estimates of reserves as defined under SEC rules. Resource estimates and estimates of non-proved reserves include potentially recoverable quantities that are subject to substantially greater risk than proved reserves. ADDITIONAL INFORMATION The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this presentation reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this presentation or accompanying materials, we may use the term “projection”, “outlook” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. PDC intends to file a proxy statement and WHITE proxy card with the SEC in connection with its solicitation of proxies for its 2019 Annual Meeting of Stockholders (the “2019 Annual Meeting”). PDC SHAREHOLDERS ARE STRONGLY ENCOURAGED TO READ THE DEFINITIVE PROXY STATEMENT (AND ANY AMENDMENTS AND SUPPLEMENTS THERETO) AND ACCOMPANYING WHITE PROXY CARD WHEN THEY BECOME AVAILABLE AS THEY WILL CONTAIN IMPORTANT INFORMATION. Shareholders may obtain the proxy statement, any amendments or supplements to the proxy statement and other documents as and when filed by PDC with the SEC without charge from the SEC’s website at www.sec.gov. CERTAIN INFORMATION REGARDING PARTICIPANTS Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in our Annual Report on Form 10-K and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this presentation. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this presentation or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. PDC, its directors and certain of its executive officers may be deemed to be participants in connection with the solicitation of proxies from PDC’s shareholders in connection with the matters to be considered at the 2019 Annual Meeting. Information regarding the ownership of PDC’s directors and executive officers in PDC common shares is included in their SEC filings on Forms 3, 4, and 5, which can be found through the SEC’s website at www.sec.gov. Information can also be found in PDC’s other SEC filings. More detailed and updated information regarding the identity of potential participants, and their direct or indirect interests, by security holdings or otherwise, will be set forth in the proxy statement and other materials to be filed with the SEC. These documents can be obtained free of charge from the sources indicated above. 2 March 2019

PDC ENERGY – Company Overview $3.0B Market Cap(1) $4.2B Enterprise Value(1) Delaware Basin ~42,000 net acres(3) 120 MMBoe proved reserves Core Wattenberg ~96,000 net acres(2) 425 MMBoe proved reserves 545 • • • • YE18 Proved Reserves (MMBoe) (1) As of 3/21/19; assumes 66 mm shares outstanding; (2) Niobrara & Codell only. (3) 2018 Year-End net acreage count of ~51,400. ~9,500 net acres (primarily in Western Culberson County) to expire by end of 1Q19. Additional ~8,400 anticipated to expire or be monetized in remainder of 2019. Anticipated YE19 net acreage count of ~33,500. 3 March 2019

FINANCIAL STRENGTH – Balance Sheet, Leverage and Liquidity As of December 31, 2018 $1,500 (1) 4Q18 adjusted cash flow from operations of $233.1 less 4Q18 O&G capital investments of $205.9; (2) Assumes weighted-average floor prices 4 March 2019 Debt Maturity Schedule (millions) Revolver $1,250 $1,000 $750 $500 Convertible $250 $0 20192020202120222023202420252026 5.75% Senior Notes 6.125% Senior 1.125% Notes Notes Leverage and Liquidity •YE18 leverage ratio improved to 1.4x from 1.9x at YE17 •~$30 million drawn on revolver (12/31/18) •4Q18 free cash flow of ~$25MM(1) •Total liquidity of ~1.3 billion Hedge Portfolio •~50% of 2019e oil production hedged at ~$55/Bbl(1) •8.6 MMBbls 2020 oil hedged at ~60/Bbl(1) •~25% of 2019e gas production hedged at ~$2.90/MMBtu(1)

CORE STRATEGIC PRIORITIES – Built to Deliver Sustainable, Long-Term Value PRIORITIZE HEALTH, SAFETY & THE ENVIRONMENT PDC’s top priority. Be a good neighbor in the communities in which we live and operate while minimizing our operational footprint MAINTAIN COMPETITIVE, HIGH-VALUE INVENTORY Create value through strategic acreage trades, focused innovation/exploration and opportunistic acquisitions BUILD A BEST-IN-CLASS ORGANIZATION Focus on the training and development of our future leaders while preserving our differentiating team-based culture Long-Term Value Creation DRIVE EFFICIENCY THROUGH TECHNOLOGY & INNOVATION Continuously pursue excellence in all we do by quickly adapting to successful technical innovation 5 March 2019 DELIVER SUSTAINABLE & PEER-COMPETITIVE RESULTS Emphasis on sustainable free cash flow with a more moderate growth profile while preserving operational flexibility PROVIDE TOP-TIER FINANCIAL & PERFORMANCE METRICS Maintain top-tier Balance Sheet strength and cash flow growth through extensive planning and scenario analysis

STRATEGIC PRIORITIES – Adapting to the Changing Landscape Multi-Year Planning Focused to Achieve Specific Targets at $50 Oil & $3 Gas 1 Sustainable FCF PRI2ORITIE Target both G&A and LOE per Boe of < $3/Boe S 3 Emphasis on FCF Margin(1) 4 Solid Growth (1) Free cash flow divided by capital investment 6 March 2019 Debt-adjusted CFPS growth of >10% Production per share growth of >10% Return on Capital Average portfolio rate-of-returns of >50% Financial & Operational Discipline Achieve CF Neutrality at $45/Bbl Year-over-year growth in FCF of >$50MM Consideration of opportunities to return capital to shareholders

PDC ENERGY – 2019 Plan Expected to Deliver Differentiating Results $50/Bbl WTI and $3/Mcf NYMEX Prices Adj. Cash Flow from Ops Capital Investment(1) 1000 ($840 - $890MM) ($810 - $870MM) 900 DE Midstream (~$40MM) 800 700 Oil & Gas Investment ($770 - $830MM) 600 500 (1) Does not include corporate capital of ~$20MM related to installation of Enterprise Resource Planning systems 7 March 2019 2019 Guidance Overview •Plan targets free cash flow generation at $50/bbl oil -Capital investments ~$150MM lower than 2018 -Every $5/bbl change in NYMEX oil price adjusts anticipated cash flows by ~$40MM •Production growth of ~20% to 46 – 50 MMBoe -Anticipate slight decline in volumes from 4Q18 to 1Q19 before steady growth through remainder of 2019 •Oil & Gas Investments – ($770 - $830MM) -Wattenberg – Plan to run 3 rigs and 1 completion crew -Delaware – 2.5 rig pace planned with a part-time completion crew •Delaware Basin Midstream – (~$40MM) -Portion of investment expected to be recovered in net proceeds of ongoing monetization process

FINANCIAL GUIDANCE – 2019 Full-Year Guidance 2019 Guidance LOE/Boe $4.00 • • Production:46 – 50 MMBoe Capital Investments: $810 – $870 $2.85 - $3.15 $3.00 2019e Commodity Mix Price Realizations (% NYMEX) (ex. TGP) $2.00 Oil: Gas: NGL: 90 – 95% 50 – 55% 30 – 35% $1.00 21-23% $-41-45% 2016 2017 2018 2019e 33-37% TGP/Boe G&A/Boe $1.50 $6.00 Oil Natural Gas NGLs $0.80 - $1.00 $1.00 $4.00 $3.00-$3.40 $0.50 $2.00 $-$- 2016 2017 2018 2019e 2016 2017 2018 2019e 8 March 2019

2019-2020 OUTLOOK – Prioritizing Free Cash Flow & Debt-Adj. Per Share Growth Production and Leverage Ratio Outlook 80 70 60 50 40 30 20 10 0 2.0x Production Leverage Ratio 1.5x 1.0x 0.5x 0.0x 2018 2019e 2020e (1) Does not include corporate capital. Delaware midstream capital investment of $77MM, ~$40MM and $0 in 2018, 2019 & 2020, respectively; (2) Midpoint of cash flow deficit/free cash flow divided by midpoint of total capital investment. (2018 FCF Margin = -$176MM/$985MM = -18%); (3) Uses 2018 average share price of $51.48 9 March 2019 MMBoe Leverage Ratio 2020 Considerations •Increase DUC count throughout 2019 -Ability to manage completions in 2020 •Additional Delaware basin completions due to potential for operational efficiencies •Consider return of capital to shareholders at sustainable levels when consistent quarterly FCF generation achieved 2018 2019e 2020e Capital Investment (MM)(1) $985 $810 - $870 $825 - $925 (Outspend)/FCF (MM) ($176) ~$25 $100 - $200 Free Cash Flow Margin(2) (18%) ~3% ~15% Prod. Growth/Debt-Adj. Share(3) ~20% ~20% ~15-20% NYMEX Pricing (Oil/Gas) $64.77/$3.09 $50/$3 $50/$3 Rig Count (WB/DE) 3/3 3/2.5 3/2 2019 Highlights •Commitment to capital discipline -Capital investments reduced ~$150MM from 2018 -Anticipate generating FCF of ~$25MM at $50 WTI •Improving balance sheet with steady production growth -Anticipate YE19 leverage ratio of ~1.3x at $50 WTI -Solid production growth per debt-adjusted share of ~20%

ASSET OVERVIEW

CORE WATTENBERG – Prolific Asset in Development Mode 96,000 ~Net Acres(1) 4Q18 Results 425 YE18 Proved Reserves (MMBoe) (1) Niobrara and Codell only. 11 March 2019 97,080 Boe/d 16% Q/Q Growth 40 Spuds 40 TILs Kersey Area Plains Area Prairie Area

CORE WATTENBERG – Safely Developing Rural Acreage in Weld County • PDC has operated in the Wattenberg Field of the DJ Basin for almost 20 years -Field office of ~250 employees located in Evans • Consolidated acreage position minimizes surface usage • Extensive history of positive working relationships with surrounding communities, regulators and elected officials -Support multiple community organizations through year-round charitable giving and volunteerism • ~100% of PDC net acreage in rural Weld County -County voted 75% No on Proposition 112 in November 2018 • ~5% of gross acreage located within municipal boundaries -Anticipate ~100% can be reached through long-lateral development from outside municipal boundary PDC Acreage I-25 Interstate State Highway City Boundary 12 March 2019 LARIMER COUNTY WELD COUNTY Fort Collins Greeley Kersey Evans Kersey Area Gilcrest Plains Area Eaton Prairie Area

Core Wattenberg – 2019 Plan Significantly Enhances Efficiencies TILs by Lateral Length 2019 2018 SRL MRL XRL 139 TILs 110-125 TILs Net WI Lateral Feet (thousands) 8,000 6,000 4,000 2,000 0 YE17 2018 TILs YE18 (1) Source: DCP press release dated 2/11/19; (2) Reflects impact of 2018 strategic acreage trade 13 March 2019 ~85 DUCs ~1,500 Locations ~6,300’ Avg. Lateral 79% WI ~120 DUCs ~920 Locations(2) ~8,250’ Avg. Lateral 85% WI 139 TILs •Capital investment of ~$500 MM -Three rigs and one completion crew -SRL/MRL/XRL well costs of $3/$4/$5 MM with average spud to spud drill times of 5/7/9 days •Continued focus on capital efficiency -Long laterals -Increased working interests -Reduced surface locations •Planned third-party midstream expansions to unlock tremendous value -Relatively flat production expected in 1Q19 from 4Q18 before steady growth through year-end -Plant 11 assumed to begin gradually coming online in June 2019(1) -Associated bypass expected to begin in August 2019

CORE WATTENBERG – Production Unbundling with Midstream Expansions DCP - Additional compression 2018-19 Processing Plant Expansions Aka - Processing Plant Compression (1) Source: DCP Midstream press release dated 2/11/19 14 March 2019 DCP Midstream – 1.05 Bcf/d •Plant 10 (Mewbourne 3): -In-service August 1, 2018 •Plant 11 (O’Connor 2): -200 MMcf/d (expected start-up in June 2019) -100 MMcf/d bypass (expected start-up in August 2019) •Plant 12 (Big Horn): -Up to 1 Bcf/d (including bypass) -First-phase start-up expected in 2020 (~300 MMcf/d) Aka Energy •Processing capacity of ~40 MMcf/d •Additional capacity via offloads to WES system Other DJ Basin Anticipated Expansions •Rimrock, Discovery, Western Gas, Outrigger expected to benefit entire basin (~1 Bcf/d additional capacity) Grand Parkway ersey Area ns Areaant 11 Plant 10 Prairie Area K Pl Pl ai

DELAWARE BASIN – Primary Focus in Two Oil-Rich Areas 42,000 ~Net Acres(1) 4Q18 Results 120 YE18 Proved Reserves (MMBoe) (1) 2018 Year-End net acreage count of ~51,400. ~9,500 net acres (primarily in Western Culberson County) to expire by end of 1Q19. Additional ~8,400 anticipated to expire or be monetized in remainder of 2019. Anticipated YE19 net acreage count of ~33,500. 15 March 2019 30,840 Boe/d 19% Q/Q Growth 9 Spuds 4 TILs

DELAWARE BASIN – Focused on Continued Execution Delaware Production (Boe/d) 35,000 31,000 30,000 25,000 25,000 20,000 15,000 10,000 5,700 5,000 0 Dec. '16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 16 March 2019 Boe/d 26,000 21,000 16,000 13,000 10,000 7,000 •Anticipate a 2.5 rig pace and part-time completion crew in 2019 •Successful marketing and midstream efforts ensure flow assurance at competitive prices -~90% of 2019 oil volumes expected to receive Brent-based pricing -Natural gas flow assurance •Midstream monetization process continuing to progress with expected execution in 1H19 -2019 capital investments associated with midstream infrastructure of ~$40MM (part expected to be recovered through divestiture)

Delaware Basin – Steady Progress Towards Development Mode TILs by Lateral Length 2019 2018 SRL MRL XRL 26 TILs 20-25 TILs Costs per Well – MRL/XRL $12.5 - $15.0 $16 $12 $8 stage spacing $4 Days Days $0 2018 2019e (1) Gross operated inventory primarily targeting the WCA and WCB zones within our oilier Eastern and North Central areas. Some locations are within untested target zones that may be subject to a higher degree of uncertainty or may depend on additional delineation testing. (2) XRL spud to rig release 17 March 2019 millions ~2,400 lbs/ft ~160’ stage spacing ~36 (2) $11.5 - $13.0 ~2,000 lbs/ft ~200’ ~34 (2) •Capital investment of ~$350 MM -Includes ~$40 MM of planned midstream investment (portion of which expected to be refunded if divested) -Project ~20% increase in lateral feet TIL’d compared to 2018 •Expect decreased average well costs due to modified completion design -Increased stage spacing -Additional benefits possible through pad drilling efficiencies, faster drill times, service cost reductions •Anticipate 2.5 rig pace and part-time completion crew -~2/3 of 2019 TILs focused in Block 4 -All 2019 TILs expected to be MRL or XRL •Inventory of ~365 identified locations with average lateral length of ~7,900’(1)

Delaware Basin – 2019 Plan Focused on Oily Areas of Block 4 Continue to Test Optimal Spacing Design Pad 18 March 2019 Block 4 Wolfcamp A Grizzly Anticipated TIL Breakdown 2019 2020 Area 1 - - Area 2 25% 60% Area 3 40% 15% North Central 35% 25% 2019 Program •Focus on multi-well pads, longer-laterals and spacing design •Continue to refine Area boundaries and type curves •Anticipate first Bone Spring TIL in 2Q19 •Tinman Project – Seven well pad in Area 3 designed to test several spacing assumptions: -Parent/child (WCA) -Vertical spacing in WCB & between zones (WCA/WCB) -Horizontal spacing in WCB -Anticipate similar performance as Grizzly Pad Grizzly Pad performance •Artificial lift has stabilized production profile •Key findings to-date: -Upper WCA wells showing strongest performance -Lower WCA wells producing in-line with average WCB -Overall project underperformance believed to be associated with localized rock and fluid properties not spacing

PDC ENERGY – Delivering Strong Value in 2019 at $50 Oil $50/Bbl WTI and $3/Mcf NYMEX Prices Returns Results Responsibility $810-$870 2019e Capital Investment (MM) 46-50 2019e Production (MMBoe) Strong Returns on Core Wattenberg and Delaware basins projects generate solid debt-adjusted per share growth in 2019 Prolific Results help generate free cash flow of ~$25 million at $50/Bbl WTI oil in 2019 41-45% 2019e % Oil ~$25 2019e Free Cash Flow (MM) Corporate Responsibility focused on sustainable operations with safe and responsible development of our assets 19 March 2019

Investor Relations Mike Edwards, Senior Director Investor Relations michael.edwards@pdce.com Kyle Sourk, Manager Investor Relations kyle.sourk@pdce.com Corporate Headquarters PDC Energy, Inc. 1775 Sherman Street Suite 3000 Denver, Colorado 80203 303-860-5800 Website www.pdce.com

/ , ,

EXECUTIVE COMP. – New Metrics Demonstrate Commitment to Capital Efficiency 50% Qualitative & 50% Quantitative 1 Percentage measurement of free cash Proposed New Metrics 2 Ability to create cash flow in a capital efficient 3 Ensures focus on cost structure 4 Measurement of operational success 5 One-year measurement of F&D 22 March 2019 Capital Efficiency (capital invested divided by EURs of TILs) Production Moderate growth with focus on FCF Rationale for New Metrics •FCF Margin -Measures ability to deliver organic FCF in range of oil prices -Mgmt. has ultimate control to manage capital investment •Debt-Adj. CFPS -Multi-year analysis indicates strong correlation to share price performance LOE and G&A/Boe and profitability Debt-Adj. Cash Flow per Share manner without change to capital structure Free Cash Flow Margin flow divided by capital investments 2 0 1 9 M E T R I C S

Strong Improvements in Quarterly Production and LOE/Boe • Declining LOE per Boe coincides with unbundled Wattenberg production -Full-year Wattenberg LOE of less than $3/Boe • Steady Delaware basin execution deliver competitive lifting costs of ~$4.15/Boe in 2018 LOE ($/Boe) $4.00 $3.44 $3.33 $3.27 $2.83 $3.00 $2.00 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 23 March 2019 $2.98$2.98 $3.06 $2.50 •Strong Wattenberg performance due to steady third-party processing throughput -Kersey line pressures still elevated though showed modest improvement by year-end •Late 3rd quarter and early 4th quarter Delaware TILs drive strong sequential production growth Production 150,000 (Boe/d) 128,000 99,000103,000 100,00088,10092,50094,100 50,000 1Q172Q173Q174Q171Q182Q183Q184Q18 110,000 73,900

PDC ENERGY – Exiting 2018 with Strong Momentum Returns Results Responsibility 40.2 2018 Production (MMBoe) ~130 Dec. ‘18 Exit Rate (Mboe/d) Strong Results drive 4Q18 growth of 17% compared to 3Q18 with a December exit rate of ~130,000 Boe/d Solid Returns generate free cash flow in 4Q18 and set stage for sustainable future free cash flow generation 1.4x YE18 Leverage Ratio 42% 2018 Crude Oil Corporate Responsibility focused on sustainable operations with safe and responsible development of our assets 24 March 2019

PDC ENERGY – Solid Growth in 2018 SEC Proved Reserves • 20% increase in proved reserves 329% all-sources reserve replacement(1) 66% increase in before-tax SEC PV-10(2) to ~$5.3 billion Stress-tested reserves at $50/bbl WTI flat • • Lost ~2% of proved reserves Net Additions(3) Year-End 2017 2018 Production Year-End 2018 (1) All-sources reserve replacement defined as sum of the year-over-year net additions in proved reserves from extensions, revisions, dispositions and acquisitions, divided by 2018 estimated production; (2) 2018 SEC NYMEX pricing: $65.56/Bbl and $3.10/MMBtu gas; (3) Net Additions is extensions, revisions, dispositions and acquisitions. 25 March 2019 Proved Reserves Summary (MMBoe) 600 Wattenberg Delaware Utica 500 400 300 200 +132.2 544.9 452.9 B-Tax PV-10 (MM) $5,321 B-Tax PV-10 (MM) $3,212 (40.2) 2017 (MMBoe) 2018 (MMBoe) Liquids (2018) Wattenberg 350.8 425.4 57% Delaware 97.9 119.5 68% Utica 4.2 - - Total 452.9 544.9 59%

PDC ENERGY – Corporate Social Responsibility SAFE OPERATIONS EMPLOYEES MATTER COMMUNITY OUTREACH 26 March 2019

Hedge Position Hedges in Place as of 12/31/18 CRUDE OIL NATURAL GAS 2019 2020 2019 Volumes (MMBbls) Collar Volumes (BBtu) Collar Swap 2.6 3.6 - 26,008 Swap 8.4 5.0 Total Crude Oil Hedged 11.0 8.6 Total Natural Gas Hedged 26,008 Crude Oil Price ($/Bbl) Floor Ceilings NYMEX Swap Natural Gas Price ($/Mmbtu) Floor Ceilings $56.54 $68.13 $53.86 $55.00 $71.68 $62.07 $ $ - - NYMEX Swap(1) $2.91 Weighted Average Price (floor) $54.50 $59.11 Weighted Average Price (floor) $2.91 (1) Corresponding CIG Basis swaps in place averaging ($.78) 27 March 2019

Reconciliation of Non-U.S. GAAP Financial Measures Adjusted Net Income (Loss) Three Months Ended Twelve Months Ended December 31, December 31, 2018 2017 2018 2017 Adjusted net income (loss): Net income (loss) (Gain) loss on commodity derivative instruments Net settlements on commodity derivative instruments Tax effect of above adjustments Adjusted net income (loss) Weighted-average diluted shares outstanding Adjusted diluted earnings per share $ 178.9 (403.0) (25.0) 102.4 $ 77.6 $ 90.4 (8.9) (28.2) 2.0 $ (145.2) (115.5) 62.4 (127.5) 3.9 13.3 (4.1) $ (146.7) $ 130.9 $ (196.3) $ (114.4) 66.2 66.1 66.3 65.8 $ (2.22) $ 1.98 $ (2.96) $ (1.74) Adjusted Cash Flows from Operations Three Months Ended December 31, Twelve Months Ended December 31, 2018 2017 2018 2017 Adjusted cash flows from operations: Net cash from operating activities Changes in assets and liabilities Adjusted cash flows from operations $ 311.5 (78.4) $ 177.2 (2.6) $ 889.3 $ (80.9) 597.8 (15.7) $ 233.1 $ 174.6 $ 808.4 $ 582.1 Reconciliation of PV-10 Year-end 2018 Year-end 2017 PV-10 Present value of estimated future income tax discounted at 10% Standardized measure of discounted future net cash flows $ 5,321 $ 3,212 (873) (332) $ 4,448 $ 2,880 28 March 2019

Reconciliation of Non-U.S. GAAP Financial Measures Adjusted EBITDAX Three Months Ended Twelve Months Ended December 31, December 31, 2018 2017 2018 2017 Net income (loss) to adjusted EBITDAX: Net income (loss) (Gain) loss on commodity derivative instruments Net settlements on commodity derivative instruments Non-cash stock-based compensation Interest expense, net Income tax expense (benefit) Impairment of properties and equipment Impairment of goodwill Exploration, geologic and geophysical expense Depreciation, depletion and amortization Accretion of asset retirement obligations Loss on extinguishment of debt Adjusted EBITDAX $ 178.9 (403.0) (25.0) 5.4 18.1 59.1 264.2 — 1.6 149.8 1.3 — $ 77.6 90.4 (8.9) 4.8 19.6 (140.4) 3.4 — 3.4 108.5 1.4 24.7 $ 2.0 $ (145.2) (115.5) 21.8 70.3 5.4 458.4 — 6.2 559.8 5.1 — (127.5) 3.9 13.3 19.4 76.4 (211.9) 285.9 75.1 47.3 469.1 6.4 24.7 $ 250.4 $ 184.5 $ 868.3 $ 682.1 Cash from operating activities to adjusted EBITDAX: Net cash from operating activities Interest expense, net Amortization of debt discount and issuance costs Gain (loss) on sale of properties and equipment Exploration, geologic and geophysical expense Exploratory dry hole costs Other Changes in assets and liabilities Adjusted EBITDAX $ 311.5 18.1 (3.3) 2.8 1.6 (0.1) (1.8) (78.4) $ 177.2 19.6 (3.3) — 3.4 (0.1) (9.7) (2.6) $ 889.3 70.3 (12.8) (0.4) 6.2 (0.1) (3.3) (80.9) $ 597.8 76.4 (12.9) 0.7 47.3 (41.3) 29.8 (15.7) $ 250.4 $ 184.5 $ 868.3 $ 682.1 29 March 2019

Commonly Used Definitions Boe – Barrel of oil equivalent Btu – British thermal unit EBITDAX 30 March 2019 Bbl – BarrelGross Margin – Oil, gas and NGL sales less LOE, TGP and prod. tax, as a % of oil, gas and NGL sales Leverage Ratio – as defined in our revolving credit facility agreement; similar to Debt to CAGR – Compound Annual Growth RateLOE – Lease operating expenses CFPS – Cash flow per shareMM – Million CWC – Completed well costMMcf – Million cubic feet D&C – Drilling and CompletionsRoR – Rate of Return EBITDAX – Earnings before interest, taxes, depreciation, amortization and exploration SRL/MRL/XRL – Standard-, Mid-and Extended-reach lateral EUR – Estimated Ultimate RecoverySWD – Salt-water disposal FCF – Free Cash Flow (cash flows from operations less capital investments)TGP – Transportation, gathering and processing FCF Margin – Free cash flow divided by capital investmentsTIL – Turn-in-line