ENERCOM S THE OIL AND GAS CONFERENCE. August 14, 2017

Transcription

1 ENERCOM S THE OIL AND GAS CONFERENCE August 14, 2017

2 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 the company s business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of Words such as expects, anticipates, intends, plans, believes, seeks, estimates, guidance, vision and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: the recent Delaware Basin acquisitions; estimated future production (including the components of such production), sales, expenses, cash flows, liquidity and balance sheet attributes (including leverage ratios); estimated crude oil, natural gas and natural gas liquids ( NGLs ) reserves; the impact of prolonged depressed commodity prices, including potentially reduced production and associated cash flow; anticipated capital projects, expenditures and opportunities; expected capital budget allocations; operational flexibility and ability to revise development plans, either upward or downward; availability of sufficient funding and liquidity for the capital program and sources of that funding; expected net settlements on derivatives for 2017; future exploration, drilling and development activities, including non-operated activity, the number of drilling rigs expected to run and lateral lengths of wells; expected 2017 production and timing of turn-in-lines; potential for future impairments; expected expansion of gas processing systems and expected line pressure; compliance with debt covenants; impact of litigation on the results of operations and financial position and future strategies, plans and objectives, including all multi-year forecasts and activity projections through The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements made in this presentation reflect PDC s good faith judgment, such statements can only be based on facts and factors currently known to PDC. 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, the Company uses the terms outlook, projection, vision or similar terms or expressions, to indicate that it has modeled certain future scenarios. PDC typically uses these terms to indicate its current thoughts on possible outcomes relating to its business or the industry in periods beyond the current fiscal year. In addition to being subject to additional levels of uncertainty generally, forward-looking statements regarding such prospective matters do not necessarily reflect the outcomes the Company views as the most likely to occur, but instead are shown to illustrate aspects of its business in the context of a variety of scenarios it believes to be plausible. PDC urges you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in the Company s Annual Report on Form 10-K for the year ended December 31, 2016, and PDC s other filings with the U.S. Securities and Exchange Commission ( SEC ), which are incorporated by this reference as though fully set forth herein, for further information on risks and uncertainties that could affect the Company's business, financial condition, results of operations and cash flows. The Company cautions you not to place undue reliance on forward-looking statements, which speak only as of the date hereof. PDC undertakes 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. 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. Nonproved 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 PDC Energy, Inc. All Rights Reserved. 8/14/2017 2

3 PDC Energy Strategic Overview Strategic Overview Top-Tier Growth Profile Capital Efficient Drilling Technical Innovations Marketing & Midstream Financial Discipline Shareholder Value Creation < 2.0x Leverage Ratio (1) ( ) ~35% 3-year Production CAGR ( ) < $3 2017e Corporate LOE/Boe 2,600 ~ Drilling Inventory < $4 Avg. Corporate Oil Differentials (2) ($/Bbl) 15% Watt. Drilling Efficiency Gains (1) Leverage Ratio is defined in revolving credit facility agreement; (2) Excludes Transportation, Gathering and Processing (TGP); (3) Well-head economics assumes base case pricing, reflects basin differentials and excludes G&A 8/14/2017 3

4 PDC Energy Premier Assets Provide Top-Tier Growth $2.7B Market Cap (1) Core Wattenberg ~95,500 net acres 1,800 identified locations (2) 305 MMBoe proved reserves $3.8B Enterprise Value (1) 2,600 ~ Horizontal Locations Utica Shale Delaware Basin ~60,000 net acres 785 identified locations (3) 33 MMBoe proved reserves 341 YE16 Proved Reserves (MMBoe) e TILs e Production (MMBoe) 40+% 2017e Annual Production Growth (1) As of 8/11/17; assumes 65.9 mm shares outstanding; (2) YE16 ~700 proved and ~1,100 probable; (3) As of YE16 Reflects 5,000 laterals in Eastern and Central areas and 10,000 laterals in Western area 8/14/2017 4

5 PDC Energy Track Record of Delivering Value Gross Margin (%) NYMEX Oil ($/Bbl) $25 Operating Costs ($/Boe) LOE per BOE TG&P Production Taxes G&A 100% Gross Margin (2) Gross Margin NYMEX Oil $ Oil Production (MMBbls) $20 $15 80% 60% $80 $60 10 $10 40% $40 5 $5 20% $20 $0 (1) e 0% e $ e 9.3 MMBoe 15.4 MMBoe 22.2 MMBoe e MMBoe 8/14/2017 (1) Excludes fees related to Delaware Basin acquisition; (2) Gross margin is defined as oil gas and NGL sales less LOE, TGP and production tax, expressed as a percent of oil, gas and NGL sales 5

6 PDC Energy Second Quarter Results 88,078 (Boe/d) 62% Year-over-Year Oil Prod. Increase (Bbls/d) $2.50 LOE/Boe 15% Wattenberg Drilling Efficiency Improvements 2017 Second Quarter Highlights Continued execution in Wattenberg drives strong results Drill times improved ~15% on SRL, MRL and XRL wells Wattenberg LOE reduced 17% from 2Q16 to $2.22/Boe ~75,620 Boe/d 2Q17 production Solid Results in Delaware program ~10,050 Boe/d represents ~50% production increase (2Q17 v 1Q17; 6 TILs; 5 spuds New Eastern and Central Area wells producing above type curves Infrastructure investment delivering PDP production optimization in Central Area 2Q17 midstream investment of $7 million Continued focus on strong financial positioning Liquidity of $902 million Leverage ratio (1) improved to 1.9x Robust hedge positions enable predictability of margins 8/14/2017 (1) Leverage ratio is defined in revolving credit facility agreement 6

7 MMBoe Leverage Ratio PDC Energy Capital Efficiency in a $50 and $3 World $50/Bbl and $3/Mcf NYMEX Prices Held Flat : Mid-Year $50/$3 Case vs. Analyst Day Base Case: Expect to maintain six rig pace through 2019 compared to acceleration to 11 rigs in AD Base Case Production and Leverage Ratio Outlook Production Range Leverage Ratio 4.0x 3.0x 2.0x ~$400 million reduction in 3-year total capital spend x Anticipate cash flow neutrality in 2019 at $50/Bbl NYMEX e 2018e 2019e 0.0x Projected YE19 Leverage Ratio of 1.1x vs 0.9x in AD Base Case $50/Bbl vs $61/Bbl NYMEX in AD Base Case Capital efficient production growth 2019e production only <5% below AD Base Case projections ~35% 3-year CAGR ( 16-19) $50/Bbl and $3/Mcf NYMEX 2017e 2018e 2019e YE Leverage Ratio ~1.8x ~1.6x ~1.1x Capital Investment (MM) ~$800 $850 - $900 $900 - $1,000 Outspend (Capex/Cash Flow) ~45% ~25% ~0% YE Cash/(Revolver) (MM) $100 - $150 (0 15% drawn) (1) (0 15% drawn) (1) Production Profile ~32 MMBoe (~45% YoY growth) 20 30% growth 30 40% growth Rig Program (WB/DE) 3/3 3/3 3/3 (1) Assumes $700 million revolving credit facility 8/14/2017 7

8 PDC Energy 2017 Production & Capital Guidance 2017e Production (MMBoe) Anticipate Closer to 32 MMBoe Production Growth Wattenberg Plan to return to 3 rigs in 4Q17 ~30% annual production growth 155 Spuds 133 TILs with ~7,300 avg. lateral length 86% WI Delaware Maintain 3 rig pace through remainder of Spuds 20 TILs with ~7,900 avg. lateral length 92% WI 2017e Production Mix ~23% NGL ~37% Gas ~40% Oil Increase in Lateral Feet Drilled e Spuds e TILs ~95,000 December 17 Exit Rate (Boe/d) ~50% Year-Over-Year Increase in Oil Production 8/14/2017 8

9 PDC Energy 2017 Capital Investment Program and Financial Guidance 2017e Capital Investment (millions) YE17e Cash Balance (1) (millions) YE17e Leverage Ratio (1) Capital Investment Details 2017e capital investment of ~$800 MM Wattenberg: ~$450 MM Delaware: ~$345 MM Includes $35 MM midstream, $30MM leasing & seismic Exploration and G&G (2) expense: $5-10 MM Price Realizations Oil: 92 94% Gas: 70 72% NGL: 27 31% Production tax: 6 8% of sales 2017e Capital Investments Wattenberg Delaware Delaware Midstream $ $3.00 LOE/Boe $ $3.60 G&A/Boe $ $0.90 TGP/Boe $ $16.50 DD&A/Boe (1) Includes ~$40 million proceeds from sale of MK note. (2) G&G = Geologic and Geophysical 8/14/2017 9

10 Robust Hedge Position Insulates Capital Program 2017 and 2018 Hedges in Place as of 6/30/17 Plus Hedges Entered Into prior to August 3, 2017 CRUDE OIL 2H Volumes (MMBbls) Collar Swap Total Crude Oil Hedged NATURAL GAS 2H Volumes (BBtu) Collar 5,900 5,230 Swap 19,620 51,280 Total Natural Gas Hedged 25,520 56,510 Crude Oil Price ($/Bbl) Floor $49.54 $41.85 Ceilings $62.32 $54.31 NYMEX Swap $50.13 $52.34 Weighted Average Price (floor) $49.98 $50.47 Natural Gas Price ($/Mmbtu) Floor $3.38 $3.00 Ceilings $4.02 $3.54 NYMEX Swap $3.40 $2.95 Weighted Average Price (floor) $3.40 $2.95 CIG Basis Swaps 2H17: 25,128 BBtu hedged at ($0.33) off NYMEX; 2018: 30,200 BBtu hedged at ($0.34) off NYMEX Waha Basis Swaps 2018: 6,000 BBtu hedged at ($0.50) off NYMEX Propane Hedges 2H17: 31.8 million gallons at $0.64/gallon; 2018: 12.0 million gallons at $0.65/gallon 8/14/

11 PDC Energy Balance Sheet Strength and Liquidity As of June 30, 2017 Leverage and Liquidity $902 million liquidity $202 million cash balance Leverage ratio (1) of 1.9x $1,000 $750 Debt Maturity Schedule (millions) Debt Maturities $700 million credit facility due May 2020 $200 million 1.125% convertible notes due Sept $500 million 7.75% senior notes due Oct $400 million 6.125% senior notes due Sept $500 $250 Corporate Ratings Moody s B1 ( Positive Outlook ) S&P B+ ( Positive Outlook ) $ Undrawn Revolver 7.75% Senior Notes 1.125% Convertible Notes 6.125% Senior Notes (1) Leverage ratio is defined in revolving credit facility agreement 8/14/

12 ASSET OVERVIEW

13 Core Wattenberg Asset Overview ~ Net Acres 2017e TIL Breakdown (2) Outer Core ~ Acreage HBP SRL 30% MRL 24% XRL 46% Middle Core Inner Core Kersey Area Horizontal Locations (1) 305 YE16 Proved Reserves (MMBoe) e Spuds e TILs 7,300 Avg. 2017e TIL (Lateral Feet) (1) ~700 proved and ~1,100 probable locations; (2) TIL = turn-in-line; SRL = standard-reach lateral, MRL = mid-reach lateral, XRL = extended-reach lateral 8/14/

14 Days Core Wattenberg Drilling Efficiencies Days Days Continued improvement in spud-to-spud drill times SRL = 6 days MRL = 8 days XRL = 10 days Expect to spud 155 wells and TIL 133 wells in 2017 Original plan estimated 139 spuds and 139 TILs Anticipate managing TILs in 4Q17 Three rig program drills the same lateral feet as 3.75 rig program compared to Analyst Day 2017 Analyst Day 2Q17 Earnings Call All numbers approximate SRL MRL XRL SRL MRL XRL Lateral Length 4,200 6,900 9,500 4,200 6,900 9,500 Drilling days (spud-to-spud) FY17e Operated Spuds Lateral Feet Drilled (000 s) FY17e Operated TILs SRL 20 MRL 15 XRL H17 2H H17 2H H17 2H17 8/14/

15 Cumulative Gross 2-Phase Production per 4,200 (Boe) Core Wattenberg Encouraging Completion Enhancements Cumulative Gross 2-Phase Production per 9,500 (Boe) 100,000 STANDARD-REACH LATERALS 200,000 EXTENDED-REACH LATERALS 75, ,000 50, ,000 25,000 0 Row Labels 490 MBoe EUR Type Curve (based on 225 spacing) 170 Completion Spacing Days 50, Days 1,100 MBoe EUR Type Curve (based on 170 spacing) 140 Completion Spacing Completion design with 170 spacing showing modest outperformance in early days Previous method based on spacing ~22 SRL TILs planned in 2H17 Early results testing 140 completion spacing show production uplift Economic benefit outweighs additional completion cost ~30 XRL TILs planned in 2H17 8/14/

16 Core Wattenberg Midstream Overview Additional Capacity Enables Future Growth Objectives NATURAL GAS Multiple midstream providers (DCP and Aka-APC) DCP expected to gather and process ~72% of 2017e gas volumes DCP current capacity ~850 MMcf/d Working with midstream providers regarding potential additional processing/gathering capacity Grand Pkwy OIL Ample takeaway capacity projected through 2020 Plant 11 Minimal firm commitments enable competitive pricing opportunities Plant 10 DCP Planned Expansions (1) + 40 MMcf/d bypass (in-service July 2017) +200 MMcf/d plant 10 (year-end 2018) +200 MMcf/d plant 11 (mid-year 2019) Additional Compression Processing Capacity Expansions 8/14/2017 (1) Source: DCP Midstream press release, 1/4/17 16

17 Delaware Basin Asset Overview Western Central ~ Net Acres Western Central Eastern EUR (MBoe) 1,200 1,000 1, ,000 Eastern Working Int. 100% 87% 91% Average Working Interest Horizontal Locations (1) e Spuds e TILs 30% YE16 HBP Gas 3,000+ Potential Hz Locations (2) NGL 8/14/2017 (1) YE16 Reflects 5,000 laterals in Eastern and Central areas and 10,000 laterals in Western area 17

18 Delaware Basin 2017 Planned Activity and Recent Wells $280 million D&C budget Spud 24 wells 15 spuds in Eastern 7 spuds in Central 2 spuds in Western TIL 20 wells including 9 XRLs $35 million midstream infrastructure Add SWD wells and capacity Drill water supply well and construct frac pits Install gas gathering lines Western PDC Phillips State Wolfcamp A ~7,500 lateral PDC/Arris Kenosha Wolfcamp A ~10,000 lateral Central PDC/Arris Greenwich 2 well pad - Wolfcamp A & B ~7,500 laterals Eastern $30 million leasing, seismic & tech studies PDC Lost Saddle Wolfcamp A ~5,000 lateral PDC Grizzly (3) Wolfcamp B-2, A-1 ~5K -1, ~10K -2 laterals Rig Location 8/14/

19 Gross Cumulative 2-Phase Production per 5,000' of Lateral (BOE) Delaware Basin Prolific Eastern Area Well Results Boe/d 500, ,000 Sugarloaf Keyhole Hanging H Argentine Kenosha Lost Saddle Average Eastern Area Wolfcamp A Kenosha Daily Performance 300, , , Days 1,000 MBoe EUR Type Curve Days Kenosha well (1 st PDC operated 10,000 lateral) 30-day peak IP: 2,295 Boe/d (~230 Boe per 1,000 ) ~2,000 Boe/d for 100 straight days ~1,000 Bbls/d oil production for 100 straight days 50% oil mix (2-phase) Plan to TIL seven wells in Eastern area in 2H17 Six 10,000 laterals 8/14/

20 Delaware Basin Recent Central Area Wells Exceeding Type Curve Gross Cumulative 2-Phase Production per 5,000' of Lateral (BOE) Central Area Well Highlights 300,000 Central Area Wolfcamp A/B Greenwich 4H (7,500 Wolfcamp A) 30-day peak IP: 1,425 Boe/d (190 Boe/d per 1,000 ) ~55% oil (2-phase) Average cumulative production of 4 Central wells is 15+% above type curve Greenwich 3H (Wolfcamp B) ~1,200 of lateral was completed 295 Boe/d per 1, ,000 1,050 MBoe EUR Type Curve Recently spud three additional Greenwich wells Liam State continues to clean up after compression upgrade and tubing pull ~300 BBls/d oil and 3 MMcf/d gas over past week 100,000 0 Liam State HSS State Greenwich 4H Greenwich 3H Days of Production 8/14/

21 Delaware Basin Operating Efficiencies and Midstream Investments Boe/d Integration initiatives and facility upgrades/investments since time of acquisition have led to increased PDP in Central area 2,500 PDP Production Optimization (Tisdale Line and Compression Upgrades) February: Gas line upgrade Replaced ~12 miles of poly gas lines with steel lines Increased operational pressure capabilities 2,000 April: Second Westeros compression upgrade Increased capacity from ~10 MMcf/d to ~20 MMcf/d Enable production optimization projects (lower LOE) 1,500 1,000 June: Additional compression added Increased capacity from ~20 MMcf/d to ~40 MMcf/d Ample capacity for near-term development plan 500 Includes seven legacy wells: Jaymac, Ron, Tisdale, Helbing (2), Winchester and Atlantis 0 12/6/2016 1/6/2017 2/6/2017 3/6/2017 4/6/2017 5/6/2017 6/6/2017 7/6/201 8/14/

22 Marketing & Midstream Gas Throughput and Processing Overview Gas delivered to both El Paso and Waha markets Added 40,000 MMBtu/d firm transportation basin to Waha through 2020 Eagle Claw Current capacity of ~320 MMcf/d Planned expansion in 9/17 & 1/18 total incremental 400 MMcf/d Energy Transfer (ETC) Western Western Gas Central ETC/ Undedicated 3 rd Party Midstream Central Delivery Points PDC Gas Gathering ETC in northern acreage of Central area (current capacity of ~1,000 MMcf/d) Eastern PDC owned Westeros compressor station expansion recently completed Western Gas (WES) Current capacity of ~800 MMcf/d with planned expansions at both Ramsey and Mentone facilities Acquired Assets Infrastructure Investment Asset YE16 17e Adds Total Gas Gathering (miles) Produced Water Pipeline (miles) Eagle Claw SWD Wells Compression Facilities 5 (1) 4 Fresh Water Pits /14/

23 Long-Term Delaware Midstream Vision Roadmap to Incremental Value Creation Key Objectives Key Evaluations Create separate fee structures for in-field midstream services Build out PDC midstream assets & infrastructure to support development plans 100% PDC owned Long-Term: Evaluate potential 3 rd party volumes and options to operate and/or participate in gas processing plants and related infrastructure Crude oil gathering systems with initial focus on Eastern area Fresh water supply distribution options and potential produced water recycling systems Long-Term: Evaluate midstream ownership options 100% ownership, Joint Venture, potential full or partial monetization 8/14/

24 PDC Energy Key Takeaways Strategic Overview Top-Tier Growth Profile Capital Efficient Drilling Technical Innovations Marketing & Midstream Financial Discipline Shareholder Value Creation < 2.0x Leverage Ratio (1) ( ) ~35% 3-year Production CAGR ( ) < $3 2017e Corporate LOE/Boe 2,600 ~ Drilling Inventory < $4 Avg. Corporate Oil Differentials (2) ($/Bbl) 15% Watt. Drilling Efficiency Gains (1) Leverage Ratio is defined in revolving credit facility agreement; (2) Excludes Transportation, Gathering and Processing (TGP); (3) Well-head economics assumes base case pricing, reflects basin differentials and excludes G&A 8/14/

25 Investor Relations Mike Edwards, Senior Director Investor Relations Kyle Sourk, Manager Investor Relations Corporate Headquarters PDC Energy, Inc Sherman Street Suite 3000 Denver, Colorado Website

26 APPENDIX

27 Kersey Area Growing Oil Volumes Based on Previous Analyst Day Type Curves Oil volumes per well continue to grow GOR typically stabilizes after months MRL and XRL wells represent recent completion design improvements SRL 490 MBoe EUR still based on 2015 completion design SRL upside projects 600 MBoe EUR (based on % improvement similar to MRL and XRL type curves) SRL, MRL and XRLs represent 36%, 29% and 35% of 2017 planned Wattenberg development (TILs) Wattenberg Oil Production (MMBbls) SRL potential upside w/ new completions SRL Oil Volume per Well (1) (MBbls) MRL XRL e (1) Oil volumes based on EURs and % oil disclosed at previous Analyst Days 8/14/

28 Wattenberg Kersey Area XRL Type Curve at 1,100 MBoe Increased Type Curve from 850 MBoe to 1,100 MBoe in 2017 Approximately 210 currently identified Middle Core locations Increased inventory driven by 2016 acreage trade Drill times average 10 days spud-to-spud Significantly enhances efficient development of Wattenberg acreage position Wattenberg XRL Performance PDC Wells Drilled Since 2016 in Kersey Focus Area Older PDC Operated Wells Updated Completion & Flowback 1,100 MBoe XRL Type Curve Base Case Type Well Details (1) 3-Phase EUR: 1,100 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 9,500 Economic Sensitivity Comparison of Type Well IRRs and GOR Variability 96% Capital Cost: $4.5MM IRR: 100+% PV10: $8.6MM Undiscounted ROI: 4.3 Payout (months): % 100+% 51% High GOR 30% Oil Not to scale Low GOR High GOR 34% Oil 30% Oil $40 / $2.50 Stress Pricing Upside Pricing (2) Low GOR 34% Oil 8/14/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in and NYMEX oil of $53, $55, $60, $65/bbl in ; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

29 Wattenberg Kersey Area MRL Type Curve at 800 MBoe Increased Type Curve from 685 MBoe to 800 MBoe in 2017 Recently completed wells are outperforming type curve Over 380 currently identified Middle Core locations Increased inventory driven by 2016 acreage trade Drill times average 8 days spud-to-spud Wattenberg MRL Performance PDC Wells Drilled Since 2015 in Kersey Focus Area Older PDC Operated Wells Updated Completion & Flowback 800 MBoe MRL Type Curve Base Case Type Well Details (1) 3-Phase EUR: 800 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 6,900 Economic Sensitivity Comparison of Type Well IRRs and GOR Variability 84% Capital Cost: $3.5MM IRR: 100+% PV10: $6.4MM Undiscounted ROI: 4.2 Payout (months): % 100+% 43% High GOR 30% Oil Not to scale Low GOR High GOR 34% Oil 30% Oil $40 / $2.50 Stress Pricing Upside Pricing (2) Low GOR 34% Oil 8/14/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in and NYMEX oil of $53, $55, $60, $65/bbl in ; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

30 Wattenberg Kersey Area SRL Type Curve of 490 MBoe Type Curve Remains 490 MBoe Began testing tighter stage spacing in 2017 Potential upside due to new completion design being used on MRL and XRL wells Over 800 currently identified Middle Core locations Drill times average 6 days spud-to-spud Wattenberg SRL Performance PDC Wells Drilled Since 2015 in Kersey Focus Area Older PDC Operated Wells Updated Completion & Flowback 490 MBoe SRL Type Curve Base Case Type Well Details (1) 3-Phase EUR: 490 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 4,200 Economic Sensitivity Comparison of Type Well IRRs and GOR Variability Capital Cost: $2.5MM IRR: 100+% PV10: $3.6MM Undiscounted ROI: 3.5 Payout (months): % 100+% 60% 30% Not to scale High GOR 30% Oil Low GOR High GOR 34% Oil 30% Oil $40 / $2.50 Stress Pricing Upside Pricing (2) Low GOR 34% Oil 8/14/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf flat in and NYMEX oil of $53, $55, $60, $65/bbl ; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

31 Reconciliation of Non-U.S. GAAP Financial Measures Net income (loss) to adjusted EBITDAX Three Months Ended June 30, Six Months Ended June 30, Net income (loss) $ 41.3 $ (95.5) $ 87.4 $ (167.0) (Gain) loss on commodity derivative instruments (57.9) 92.8 (138.6) 81.7 Net settlements on commodity derivative instruments Non-cash stock-based compensation Interest expense, net Income tax provision (benefit) 24.5 (58.3) 50.9 (100.2) Impairment of properties and equipment Exploration, geologic and geophysical expense Depreciation, depletion, and amortization Accretion of asset retirement obligations Adjusted EBITDAX $ $ $ $ Weighted-average diluted shares outstanding Adjusted EBITDAX per diluted share $ 3.04 $ $2.62 $ 5.00 $ $4.08 Cash from operating activities to adjusted EBITDAX Three Months Ended June 30, Six Months Ended June 30, Net cash from operating activities $ $ 96.6 $ $ Interest expense, net Amortization of debt discount and issuance costs (3.2) (1.3) (6.4) (3.1) Gain (loss) on sale of properties and equipment 0.5 (0.3) 0.7 (0.2) Exploration, geologic and geophysical expense Other (1) (41.3) Changes in assets and liabilities (6.6) 5.8 Adjusted EBITDAX $ $ Weighted-average diluted shares outstanding Adjusted EBITDAX per diluted share $ 3.04 $ $2.62 $ 5.00 $ $4.08 (1) Other includes the impact of provisions for the uncollectible notes receivable in the three and six months ended June 30, 2017, and the six months ended June 30, /14/

32 Reconciliation of Non-U.S. GAAP Financial Measures Net income (loss) to adjusted net income (loss) Three Months Ended June 30, Six Months Ended June 30, Net income (loss) $ 41.3 $ (95.5) $ 87.4 $ (167.0) (Gain) loss on commodity derivative instruments (57.9) 92.8 (138.6) 81.7 Net settlements on commodity derivative instruments Tax effect of above adjustments 17.2 (55.6) 47.2 (76.8) Adjusted net income (loss) $ 12.5 $ (5.0) $ 8.5 $ (41.9) Weighted-average diluted shares outstanding Adjusted earnings per diluted share $ 0.19 $ (0.11) $ 0.13 $ (0.95) Net cash from operating activities to adjusted cash flows from operations Three Months Ended June 30, Six Months Ended June 30, Net cash from operating activities $ $ 96.6 $ $ Changes in assets and liabilities (6.6) 5.8 Adjusted cash flows from operations $ $ $ $ /14/