BAML 2017 GLOBAL ENERGY CONFERENCE November 16, 2017
Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"), and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 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 report are "forward-looking statements". Words such as expects, anticipates, intends, plans, believes, seeks, estimates, and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements may include, among other things, the closing of pending transactions and the effects of such transactions, including the fact that the pending acquisition of certain properties owned by Bayswater Exploration and Production, LLC and certain related parties are subject to continuing diligence between the parties and may not occur within the expected timeframe or may not successfully close such transaction; the level of non-operated well activity following the pending acreage exchanges; future reserves, production, costs, cash flows, and earnings; drilling locations and growth opportunities; capital investments and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments. 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 terms 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. Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in the Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2016 (the "2016 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 28, 2017, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations, and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. 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 forwardlooking 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. By making this presentation, the Company is not offering to sell or soliciting offers to purchase any securities. 2017 PDC Energy, Inc. All Rights Reserved. 11/16/2017 2
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) (2017-2019) ~35% 3-year Production CAGR (2016-2019) < $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 11/16/2017 3
PDC Energy Premier Assets Provide Top-Tier Growth $3.3B Market Cap (1) Core Wattenberg ~95,500 net acres 1,800 identified locations (2) 305 MMBoe proved reserves $4.4B 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) 153 2017e TILs ~32 2017e Production (MMBoe) 40+% 2017e Annual Production Growth (1) As of 11/10/17; 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 11/16/2017 4
PDC Energy Track Record of Delivering Value $25 Operating Costs ($/Boe) LOE per BOE TG&P Production Taxes G&A 100% Gross Margin (2) Gross Margin NYMEX Oil $100 15 Oil Production (MMBbls) $20 $15 $10 Gross Margin (%) 80% 60% 40% $80 $60 $40 NYMEX Oil ($/Bbl) 10 5 $5 20% $20 $0 (1) 2014 2015 2016 2017e 0% 2014 2015 2016 2017e $0 0 2014 2015 2016 2017e 9.3 MMBoe 15.4 MMBoe 22.2 MMBoe 2014 2015 2016 2017e ~32 MMBoe 11/16/2017 (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
PDC Energy Third Quarter 2017 Results 92,500 (Boe/d) 47% Year-over-Year Oil Prod. Increase (Bbls/d) $2.98 LOE/Boe 28% Delaware Production Increase (3Q17 v 2Q17) 2017 Third Quarter Highlights Continued execution in Wattenberg drives strong results ~77,580 Boe/d 3Q17 production 46 gross operated spuds (18 SRL; 20 MRL; 8 XRL) 39 TILs (14 SRL; 9 MRL; 16 XRL) Solid Results in Delaware program ~12,845 Boe/d represents ~28% production increase (3Q17 vs 2Q17) Initial enhanced completion design tests in Eastern area Wolfcamp A Strong results from first Wolfcamp B wells in Eastern area Continued outperformance of acquisition type curve in Central area Continued focus on strong financial positioning Liquidity of $836 million as of September 30, 2017 Leverage ratio (1) improved to 1.8x Robust hedge positions enable predictability of margins (1) Leverage ratio is defined in revolving credit facility agreement 11/16/2017 6
PDC Energy Capital Efficiency in a $50 and $3 World $50/Bbl and $3/Mcf NYMEX Prices Held Flat (Does Not Reflect Effect of Any Securities Offering or Wattenberg Transaction Announced on 9/25/17) 2017-2019: 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 ~$400 million reduction in 3-year total capital spend MMBoe 80 60 40 20 Production and Leverage Ratio Outlook Production Range Leverage Ratio 4.0x 3.0x 2.0x 1.0x Leverage Ratio Anticipate cash flow neutrality in 2019 at $50/Bbl NYMEX 0 2016 2017e 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 (1) (0 15% drawn) (2) (0 15% drawn) (2) Production Profile ~32 MMBoe (~45% YoY growth) 20 30% growth 30 40% growth Rig Program (WB/DE) 3/3 3/3 3/3 (1) Does not include anticipated closing of previously announced Wattenberg acquisition; (2) Assumes $700 million revolving credit facility 11/16/2017 7
PDC Energy 2017 Production & Capital Guidance (Does Not Reflect Potential Effect of Wattenberg Transactions Announced on 9/25/17) 2017e Production (MMBoe) Production Growth Increase in Lateral Feet Drilled Wattenberg Currently operating 3 rigs ~30% annual production growth 155 Spuds 133 TILs with ~7,300 avg. lateral length 86% WI Delaware Maintain 3 rig pace through remainder of 2017 24 Spuds 18 TILs with ~7,900 avg. lateral length 92% WI 2017e Production Mix ~23% NGL ~37% Gas ~40% Oil 179 2017e Spuds 151 2017e TILs ~95,000 December 17 Exit Rate (Boe/d) ~50% Year-Over-Year Increase in Oil Production 11/16/2017 8
PDC Energy 2017 Capital Investment Program and Financial Guidance (Does Not Reflect Potential Effect of Wattenberg Transactions Announced on 9/25/17) 2017e Capital Investment (millions) YE17e Liquidity (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 Price Realizations Oil: 92 94% Gas: 70 72% NGL: 32 36% Production tax: 6 8% of sales 2017e Capital Investments Wattenberg Delaware Delaware Midstream $2.65 - $3.00 LOE/Boe $3.25 - $3.60 G&A/Boe $0.90 - $1.10 TGP/Boe $15.00 - $16.50 DD&A/Boe (1) Pro forma anticipated 4Q17 closing of previously announced Wattenberg acquisition. 11/16/2017 9
Robust Hedge Position Insulates Capital Program Hedges in Place as of 9/30/17 Plus Hedges Entered Into prior to November 3, 2017 CRUDE OIL 4Q17 2018 2019 Volumes (MMBbls) Collar 0.6 1.5 - Swap 1.8 8.6 3.0 Total Crude Oil Hedged 2.5 10.1 3.0 Crude Oil Price ($/Bbl) Floor $49.54 $41.85 $0.00 Ceilings $62.32 $54.31 $0.00 NYMEX Swap $50.13 $52.19 $50.49 Weighted Average Price (floor) $49.98 $50.64 $50.49 NATURAL GAS 4Q17 2018 2019 Volumes (BBtu) Collar 2,895 5,230 - Swap 10,310 51,280 - Total Natural Gas Hedged 13,205 56,510 - Natural Gas Price ($/Mmbtu) Floor $3.38 $3.00 - Ceilings $4.02 $3.54 - NYMEX Swap $3.39 $2.95 - Weighted Average Price (floor) $3.39 $2.95 CIG Basis Swaps 4Q17: 13,264 BBtu hedged at ($0.34) off NYMEX; 2018: 35,200 BBtu hedged at ($0.36) off NYMEX Waha Basis Swaps 2018: 6,000 BBtu hedged at ($0.50) off NYMEX El Paso Basis Swaps 2018: 3,000 BBtu hedged at ($0.62) off NYMEX Propane Hedges 4Q17: 17.3 million gallons at $0.65/gallon; 2018: 18.0 million gallons at $0.69/gallon 11/16/2017 10
PDC Energy Balance Sheet Strength and Liquidity As of September 30, 2017 (Does Not Reflect Effect of Any Securities Offering or Wattenberg Transaction Announced on 9/25/17) $836 million liquidity $136 million cash balance Leverage ratio (1) of 1.8x Leverage and Liquidity Borrowing base increased from $950 million to $1.1 billion in October 2017 Debt Maturities $700 million credit facility due May 2020 $200 million 1.125% convertible notes due Sept. 2021 $500 million 7.75% senior notes due Oct. 2022 $400 million 6.125% senior notes due Sept. 2024 Corporate Ratings Moody s Upgraded to Ba3 ( Stable Outlook ) Nov. 2017 S&P Upgraded to BB- ( Stable Outlook ) August 2017 $1,000 $750 $500 $250 $0 Debt Maturity Schedule (millions) 2017 2018 2019 2020 2021 2022 2023 2024 Undrawn Revolver 7.75% Senior Notes 1.125% Convertible Notes 6.125% Senior Notes (1) Leverage ratio is defined in revolving credit facility agreement 11/16/2017 11
ASSET OVERVIEW
Core Wattenberg Asset Overview (Other Than Map, Does Not Reflect Potential Effect of Wattenberg Transactions Announced on 9/25/17) Post-Closings Acreage Map ~ Net Acres 2017e TIL Breakdown (2) ~ Acreage HBP SRL 30% MRL 23% XRL 47% Horizontal Locations (1) 305 YE16 Proved Reserves (MMBoe) 155 2017e Spuds 133 2017e 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 11/16/2017 13
Wattenberg Transactions Consolidate Position Increase XRL Development Potential Acreage Trades Closed in November and Bolt-On Acquisition Expected to Close in December 2017 Consolidated acreage positions favorable for XRL development Kersey: ~30,000 net acres; Prairie: ~30,000 net acres; Plains: ~17,500 net acres Post-Closings Acreage Map Prairie acquisition expected to add ~8,300 net acres and ~2,200 Boe/d (1) Adds 240 estimated gross drilling locations (~2 years of inventory at current pace) Increases working interest in ~60 PDC wells Includes 30 DUC wells plan to TIL 18 (~YE17) Plains & Prairie Area EURs and commodity mix based on industry data AREA Plains Prairie PDC completion technique not utilized in majority of data Estimated development schedule coincides with planned midstream expansion XRL EUR Gross MBoe Kersey 1,100 1,050 600 % Oil 30-34% 24-30% 40-60% Oil MBbls/Well ~350 ~285 ~300 Development Current (1) Production at time of signing, does not include any potential production associated with DUC wells; (2) Development plan reflects current expectations 11/16/2017 14 2019 2020+
Core Wattenberg Drilling Efficiencies 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) 7 10 12 6 8 10 FY17e Operated Spuds 50 51 38 47 62 46 Lateral Feet Drilled (000 s) 210 352 361 197 428 437 FY17e Operated TILs 50 41 48 40 31 62 15 SRL 20 MRL 15 XRL Days 10 5 12 7 7 6 Days 15 10 5 18 11 10 8 Days 10 5 14 12 10 0 2015 2016 1H17 2H17 0 2015 2016 1H17 2H17 0-2015 2016 1H17 2H17 11/16/2017 15
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 Post-Closings Acreage Map (1) Prairie DCP current capacity ~850 MMcf/d Working with midstream providers regarding potential additional processing/gathering capacity OIL Ample takeaway capacity projected through 2020 Kersey Plant 11 Grand Pkwy Minimal firm commitments enable competitive pricing opportunities Plains Plant 10 DCP Planned Expansions (2) + 40 MMcf/d bypass (in-service July 2017) +200 MMcf/d plant 10 (4Q 2018) +200 MMcf/d plant 11 (mid-year 2019) Additional Compression 2018-2019 Processing Capacity Expansions 11/16/2017 (1) Post closing of transactions announced on 9/25/17. (2) Source: DCP Midstream press release, 11/7/17 16
Delaware Basin Asset Overview & Planned Activity ~ Net Acres (1) $285 million D&C budget Spud 24 wells 15 spuds in Eastern 7 spuds in Central 2 spuds in Western TIL 18 wells including 8 XRLs Average Working Interest $35 million midstream infrastructure Add SWD wells and capacity Drill water supply well and construct frac pits Install gas gathering lines 2017e XRL TILs $25 million leasing, seismic & tech studies 24 2017e Spuds 18 2017e TILs 28% Production Growth (3Q17 v 2Q17) 12,845 3Q17 Production (Boe/d) (1) The Company impaired 13,400 net acres in the Western area in 3Q17. 11/16/2017 17
Delaware Basin Gaining Operational Momentum Positive well results and steady development ramp lead to strong quarterly production growth Continued improvement in completion operations 15,000 Delaware Production (Boe/d) 12,845 Focus on artificial lift, choke management and infrastructure investment yielding positive results 10,000 10,047 Fit-for-purpose rigs beginning to improve spud to TD drill times Still room for improvement Boe/d 5,000 5,735 6,810 Consistent drilling crews lead to increased efficiencies Fewer surprises with better geologic understanding 0 Dec. '16 1Q17 2Q17 3Q17 11/16/2017 18
Delaware Basin Prolific Eastern Area Wolfcamp A Well Results Gross Cumulative 2-Phase Production per 5,000' (Boe) 500,000 400,000 300,000 200,000 100,000 0 PDC Average (8 wells) Type Curve +50% Type Curve +100% 8 wells Eastern Area Wolfcamp A 6 wells 5 wells 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 Days 4 wells 1,000 MBoe EUR Acquisition Type Curve (1) 3 wells 2 wells Gross Cumulative 2-Phase Production per 5,000' (Boe) 500,000 400,000 300,000 200,000 100,000 0 Keyhole Sugarloaf Hanging H Argentine Kenosha Blue Lakes Gavster State Lost Saddle Eastern Area Wolfcamp A 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 Lost Saddle well (~4,000 lateral) 1 st enhanced clustered completion design 30-day peak IP: 1,450 Boe/d (~363 Boe per 1,000 ) Production more than double 1,000 MBoe EUR type curve on cumulative basis No additional cost for clustered completions Plan to TIL 5 wells in Eastern area in 4Q17 (4 XRLs) Days 1,000 MBoe EUR Acquisition Type Curve (1) (1) Based on industry activity in 2015 2016 11/16/2017 19
Delaware Basin Initial Eastern Area Wolfcamp B Well Results Early Data on Limited Sample Size 250,000 Triangle Eastern Area Wolfcamp B Elkhead & Kenosha Daily Performance Comparison 10000 Gross Cumulative 2-Phase Production per 5,000' (Boe) 200,000 150,000 100,000 50,000 0 Hermit Elkhead 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 Days 750 MBoe EUR Acquisition Type Curve (1) Boe/d 1000 100 10 1 Kenosha Elkhead 0 20 40 60 80 100 120 140 Days Elkhead well (~10,000 lateral Wolfcamp B) ~2,250 Boe/d last 45 days (yet to reach peak production) ~1,550 bbls/d oil Production profile similar to Kenosha well (10,000 Wolfcamp A well) Hermit well (~10,000 lateral) averaging ~1,500 Boe/d Casing PSI of ~3,800 (1) Based on industry activity in 2015 2016 11/16/2017 20
Delaware Basin Recent Central Area Wells Exceeding Type Curve Central Area Well Highlights 300,000 Central Area Wolfcamp A/B Liam State cumulative production on trend to outperform 1,050 MBoe EUR normalized type curve Greenwich 4H (Wolfcamp A) Sustained outperformance of acquisition type curve Three additional Greenwich wells planned for 2018 TIL Gross Cumulative 2-Phase Production per 5,000' (Boe 200,000 100,000 1,050 MBoe EUR Acquisition Type Curve (1) Liam State HSS State Greenwich 4H Greenwich 3H 0 0 60 120 180 240 300 360 420 Days (1) Based on industry activity in 2015 2016 11/16/2017 21
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 ~520 MMcf/d Planned expansion in 1/18 incremental 200 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 + 2017 Infrastructure Investment Asset YE16 17e Adds Total Gas Gathering (miles) 60 37 97 Produced Water Pipeline (miles) 35 35 70 Eagle Claw SWD Wells 5 3 8 Compression Facilities 5 (1) 4 Fresh Water Pits 10 3 13 11/16/2017 22
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 11/16/2017 23
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) (2017-2019) ~35% 3-year Production CAGR (2016-2019) < $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 11/16/2017 24
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
APPENDIX
Kersey Area Growing Oil Volumes Based on Previous Analyst Day Type Curves 12 10 Oil volumes per well continue to grow GOR typically stabilizes after 18-36 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 180-200 185 175 160 Oil Volume per Well (1) (MBbls) 250 245 MRL 255 305 350 XRL 8 6 4 2 0 2014 2015 2016 2017e 2015 2016 2017 2015 2016 2017 2016 2017 (1) Oil volumes based on EURs and % oil disclosed at previous Analyst Days 11/16/2017 27
Reconciliation of Non-U.S. GAAP Financial Measures (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, 2016. Adjusted EBITDAX Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Net loss to adjusted EBITDAX: Net loss $ (292.5) $ (23.3) $ (205.1) $ (190.3) (Gain) loss on commodity derivative instruments 52.2 (19.4) (86.5) 62.3 Net settlements on commodity derivative instruments 9.6 47.7 22.2 167.9 Non-cash stock-based compensation 4.8 4.1 14.6 15.2 Interest expense, net 18.8 20.1 56.9 40.9 Income tax benefit (122.4 ) (12.0) (71.5) (112.2 ) Impairment of properties and equipment 252.7 0.9 282.5 6.1 Impairment of goodwill 75.1 75.1 Exploration, geologic, and geophysical expense 41.9 0.2 43.9 0.7 Depreciation, depletion, and amortization 125.2 112.9 360.6 317.3 Accretion of asset retirement obligations 1.5 1.8 4.9 5.4 Adjusted EBITDAX $ 166.9 $ 133.0 $ 497.6 $ 313.3 Cash from operating activities to adjusted EBITDAX: Net cash from operating activities $ 148.2 $ 163.0 $ 411.4 $ 360.8 Interest expense, net 18.8 20.1 56.9 40.9 Amortization of debt discount and issuance costs (3.2) (9.9) (9.6) (13.0) Gain on sale of properties and equipment 0.1 0.2 0.8 Exploration, geologic, and geophysical expense 41.9 0.2 43.9 0.7 Exploratory dry hole (41.2) (41.2) Other (0.4) (0.2) 39.2 (41.5) Changes in assets and liabilities 2.7 (40.4) (3.9) (34.6) Adjusted EBITDAX $ 166.9 $ 133.0 $ 497.5 $ 313.3 11/16/2017 28
Reconciliation of Non-U.S. GAAP Financial Measures Adjusted Net Income (Loss) Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Adjusted net loss: Net loss $ (292.5) $ (23.3) $ (205.1) $ (190.3) (Gain) loss on commodity derivative instruments 52.2 (19.4 ) (86.5 ) 62.3 Net settlements on commodity derivative instruments 9.6 47.7 22.2 167.9 Tax effect of above adjustments (23.2 ) (10.8 ) 24.0 (87.6 ) Adjusted net loss $ (253.9 ) $ (5.8) $ (245.4) $ (47.7 ) Weighted-average diluted shares outstanding 65.9 48.8 65.8 45.7 Adjusted diluted earnings per share $ (3.85 ) $ (0.12) $ (3.73) $ (1.04 ) Adjusted Cash Flows from Operations Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 Adjusted cash flows from operations: Net cash from operating activities $ 148.2 $ 163.0 $ 411.4 $ 360.8 Changes in assets and liabilities 2.7 (40.4) (3.9) (34.6) Adjusted cash flows from operations $ 150.9 $ 122.6 $ 407.5 $ 326.2 11/16/2017 29