GOLDMAN SACHS ENERGY CONFERENCE. January 9, 2018

Transcription

1 GOLDMAN SACHS ENERGY CONFERENCE January 9, 2018

2 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 effects of the Bayswater Exploration and activity levels on the acquired acreage; 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 PDC Energy, Inc. All Rights Reserved. 1/8/18 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 (3) < $4 Avg. Corporate Oil Differentials (2) ($/Bbl) 15% Watt. Drilling Efficiency Gains (1) Leverage Ratio is defined in revolving credit facility agreement; (2) Excludes Transportation, Gathering and Processing (TGP); (3) YE16, does not include 240 locations from Bayswater Acquisition. 1/8/18 3

4 PDC Energy Premier Assets Provide Top-Tier Growth $3.5B Market Cap (1) Core Wattenberg ~95,500 net acres 1,800 identified locations (2) 305 MMBoe proved reserves $4.7B Enterprise Value (1) 2,600 ~ Horizontal Locations (2,3) 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 1/3/18; assumes 65.9 mm shares outstanding; (2) YE16 ~700 proved and ~1,100 probable, does not include 240 locations from Bayswater acquisition; (3) As of YE16 Reflects 5,000 laterals in Eastern and Central areas and 10,000 laterals in Western area 1/8/18 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 ~32 MMBoe 1/8/18 (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 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 1/8/18 6

7 PDC Energy 2018 Production and Capital Investment Guidance 2018e Production (MMBoe) 2018e Capital Investment ($ millions) Capital Investment Details (All numbers approximate) Wattenberg ($480MM) $425MM operated D&C 131 spuds & 139 TILs (85% avg. WI) Focus in Kersey Area Delaware ($395MM) $275MM operated D&C 22 spuds & 22 TILs (90% avg. WI) $60MM in midstream infrastructure $20MM for crude oil gathering $40MM for SWDs, gas gathering lines, etc. $60MM in non-op, leasing, seismic and misc. 2018e Production Mix ~22% NGL ~36% Gas ~42% Oil YE18e Leverage Ratio (1) Utica Anticipated divestiture completed in 1Q18 Proceeds not included in outspend projection ~120,000 Dec. Exit Rate (Boe/d) ~$130mm Outspend ($50 Oil/$3 Gas) 153 Spuds 161 TILs (1) Leverage ratio is defined in revolving credit facility agreement 1/8/18 7

8 Robust Hedge Position Insulates Capital Program Hedges in Place as of 9/30/17 Plus Hedges Entered Into prior to 12/31/17 CRUDE OIL Q Volumes (MMBbls) Collar Swap Total Crude Oil Hedged NATURAL GAS Q Volumes (BBtu) Collar 2,895 5,230 - Swap 10,310 51,280 - Total Natural Gas Hedged 13,205 56,510 - Crude Oil Price ($/Bbl) Natural Gas Price ($/Mmbtu) Floor $ $ $ - Floor $ 3.38 $ 3.00 $ - Ceilings $ $ $ - Ceilings $ 4.02 $ 3.54 $ - NYMEX Swap $ $ $ NYMEX Swap $ 3.39 $ 2.95 $ - Weighted Average Price (floor) $ $ $ 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: 44.0 million gallons at $0.76/gallon 1/8/18 8

9 PDC Energy Balance Sheet Strength and Liquidity Leverage and Liquidity (as of 9/30/17) $836 million liquidity $136 million cash balance Leverage ratio (1) of 1.8x Borrowing base increased from $950 million to $1.1 billion in October 2017 Debt Maturities (2) $700 million credit facility due May 2020 $200 million 1.125% convertible notes due Sept $400 million 6.125% senior notes due Sept $600 million 5.750% senior notes due May 2026 Corporate Ratings Moody s Upgraded to Ba3 ( Stable Outlook ) Nov S&P Upgraded to BB- ( Stable Outlook ) August 2017 $1,000 $750 $500 $250 $0 Debt Maturity Schedule (millions) Undrawn Revolver 5.750% Senior Notes 1.125% Convertible Notes 6.125% Senior Notes (1) Leverage ratio is defined in revolving credit facility agreement; (2) Debt maturities include transactions completed after 9/30/17. 1/8/18 9

10 ASSET OVERVIEW

11 Core Wattenberg 2017 Overview Acreage Trades Closed in November and Bolt-On Acquisition Closed in January 2018 ~ Net Acres 2017e TIL Breakdown (2) ~ Acreage HBP SRL 30% MRL 23% XRL 47% 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, does not include 240 locations from Bayswater acquisition; (2) TIL = turn-in-line; SRL = standard-reach lateral, MRL = mid-reach lateral, XRL = extended-reach lateral 1/8/18 11

12 Wattenberg Transactions Consolidate Position Increase XRL Development Potential Acreage Trades Closed in November; Bolt-On Acquisition Closed in January 2018 Consolidated acreage positions favorable for XRL development Kersey: ~30,000 net acres; Prairie: ~30,000 net acres; Plains: ~17,500 net acres 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) All numbers subject to ongoing due diligence Plains & Prairie Area EURs and commodity mix based on industry data PDC completion technique not utilized in majority of data Estimated development schedule coincides with planned midstream expansion Post-Closings Acreage Map AREA Kersey 1,100 Plains Prairie XRL EUR Gross MBoe 1, % 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 1/8/18 12

13 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 1/8/18 13

14 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 Processing Capacity Expansions 1/8/18 (1) Post closing of transactions announced on 9/25/17. (2) Source: DCP Midstream press release, 11/7/17 14

15 Delaware Basin 2017 Overview ~ Net Acres (1) 2017e Capital Investment Details $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 2017e XRL TILs $35 million midstream infrastructure Add SWD wells and capacity Drill water supply well and construct frac pits Install gas gathering lines $25 million leasing, seismic & tech studies e Spuds e 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. 1/8/18 15

16 Delaware Basin Gaining Operational Momentum Continued improvement in completion operations Clustered perf design showing encouraging initial results Increased capital efficiency from longer laterals Eastern Area Block 4 Approximate Surface Locations Elkhead 2018 TILs: 14 in Eastern Area, 11 in Block 4 Six well downspacing test (testing 12 wells per section equivalent spacing in Wolfcamp A) Initial Wolfcamp C test planned (Grizzly West) Hermit Kenosha Argentine Buzzard North Buzzard South Recent Well Result Details Lateral Length (feet) Well Name TIL Date Wolfcamp Bench 30-day Peak IP (Boe/d; 2-phase) % Oil Buzzard South 11/27/2017 B 9,805 1,641 69% Y Buzzard North 11/20/2017 A 9,861 2,944 69% Y Elkhead 8/25/2017 B 9,716 2,254 69% N Blue Lakes 8/3/2017 A 9,817 1,528 49% N Lost Saddle 5/25/2017 A 3,963 1,405 45% Y Hermit 5/12/2017 B 9,684 1,502 18% N Kenosha 3/7/2017 A 9,331 2,295 51% N Argentine 12/12/2016 A 4,553 1,185 72% N Clustered Perf Blue Lakes Grizzly Bear (6 Well Downspacing Test) TILs 2017 New TILs 2018 Expected TILs Lost Saddle Grizzly West Grizzly North Grizzly South 1/8/18 16

17 Gross Cumulative 2-Phase Production per 5,000' (Boe) Gross Cumulative 2-Phase Production per 5,000' (Boe) Delaware Basin Prolific Eastern Area Wolfcamp A Well Results (Well Data as of 11/7/17) 500, ,000 Eastern Area Wolfcamp A PDC Average (8 wells) Type Curve +50% Type Curve +100% 500, , ,000 Keyhole Sugarloaf Hanging H Argentine Kenosha Blue Lakes Gavster State Lost Saddle Eastern Area Wolfcamp A 300, , ,000 1,000 MBoe EUR Acquisition Type Curve (1) 200, , wells 6 wells 5 wells Days 4 wells 1,000 MBoe EUR Acquisition Type Curve (1) 3 wells 2 wells 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 Days Five TILs in Eastern area in 4Q17 (4 XRLs) (1) Based on industry activity in /8/18 17

18 Gross Cumulative 2-Phase Production per 5,000' (Boe) Boe/d Delaware Basin Initial Eastern Area Wolfcamp B Well Results Early Data on Limited Sample Size as of 11/7/17 250,000 Eastern Area Wolfcamp B Elkhead & Kenosha Daily Performance Comparison Triangle 200,000 Hermit Elkhead 1000 Kenosha Elkhead , ,000 50, Days 750 MBoe EUR Acquisition Type Curve (1) 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 Days (1) Based on industry activity in /8/18 18

19 Gross Cumulative 2-Phase Production per 5,000' (Boe Delaware Basin Recent Central Area Wells Exceeding Type Curve (Well data as of 11/7/17) 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 Eight Central Area TILs planned in 2018 Includes three additional Greenwich wells 200, ,000 1,050 MBoe EUR Acquisition Type Curve (1) Liam State HSS State Greenwich 4H Greenwich 3H Days (1) Based on industry activity in /8/18 19

20 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 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 /8/18 20

21 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 1/8/18 21

22 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 1/8/18 22

23 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

24 APPENDIX

25 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 Operated 3-4 rigs ~30% annual production growth 155 Spuds 133 TILs with ~7,300 avg. lateral length 86% WI Delaware Operated 3-4 rigs 24 Spuds 18 TILs with ~7,900 avg. lateral length 92% WI 2017e Production Mix ~23% NGL ~37% Gas ~40% Oil e Spuds e TILs ~95,000 December 17 Exit Rate (Boe/d) ~50% Year-Over-Year Increase in Oil Production 1/8/18 25

26 MMBoe Leverage Ratio PDC Energy Capital Efficiency in a $50 and $3 World $50/Bbl and $3/Mcf NYMEX Prices Held Flat (Does Not Reflect Actual 2018 Production & Capital Guidance on 12/11/17) : Mid-Year $50/$3 Case vs. Analyst Day Base Case: Based on 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 (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 1/8/18 26

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 Oil Volume per Well (1) (MBbls) 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 potential upside w/ new completions XRL Wattenberg Oil Production (MMBbls) MRL SRL e (1) Oil volumes based on EURs and % oil disclosed at previous Analyst Days 1/8/18 27

28 Reconciliation of Non-U.S. GAAP Financial Measures Adjusted EBITDAX Three Months Ended September 30, Nine Months Ended September 30, 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 Non-cash stock-based compensation Interest expense, net Income tax benefit (122.4) (12.0) (71.5) (112.2 ) Impairment of properties and equipment Impairment of goodwill Exploration, geologic, and geophysical expense Depreciation, depletion, and amortization Accretion of asset retirement obligations Adjusted EBITDAX $ $ $ $ Cash from operating activities to adjusted EBITDAX: Net cash from operating activities $ $ $ $ Interest expense, net Amortization of debt discount and issuance costs (3.2) (9.9) (9.6) (13.0) Gain on sale of properties and equipment Exploration, geologic, and geophysical expense Exploratory dry hole (41.2) (41.2) Other(1) (0.4) (0.2) 39.2 (41.5) Changes in assets and liabilities 2.7 (40.4) (3.9) (34.6) Adjusted EBITDAX $ $ $ $ (1) Other includes the impact of provisions for the uncollectible notes receivable in the nine months ended September 30, 2017, and the six months ended June 30, /8/18 28

29 Reconciliation of Non-U.S. GAAP Financial Measures Adjusted Net Income (Loss) Three Months Ended September 30, Nine Months Ended September 30, 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 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 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, Adjusted cash flows from operations: Net cash from operating activities $ $ $ $ Changes in assets and liabilities 2.7 (40.4) (3.9) (34.6) Adjusted cash flows from operations $ $ $ $ /8/18 29