MAY UPDATE. May 2018

Transcription

1 MAY UPDATE May 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, statements regarding 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 Annual Report on Form 10-K for the year ended December 31, 2017, filed with the U.S. Securities and Exchange Commission ("SEC") on February 27, 2018 and amended on May 1, 2018, 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 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. 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. Commonly Used Definitions Bbl Barrel Boe Barrel of oil equivalent Btu British thermal unit CAGR Compound Annual Growth Rate CWC Completed well cost D&C Drilling and Completions EBITDAX Earnings before interest, taxes, depreciation, amortization and exploration EUR Estimated Ultimate Recovery Gross 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 EBITDAX LOE Lease operating expenses MM Million MMcf Million cubic feet SRL/MRL/XRL Standard-, Mid- and Extended-reach lateral SWD Salt-water disposal TGP Transportation, gathering and processing TIL Turn-in-line 2018 PDC Energy, Inc. All Rights Reserved. May

3 PDC ENERGY Strategic Overview Returns Results Responsibility e Production (MMBoe) ~$ e Outspend (millions) ~130 Dec. 18e Exit Rate (Mboe/d) 1.3x YE18e Leverage Ratio Strong Returns on inventory ~2,000 gross locations in the Core Wattenberg and Delaware basins Prolific Results expected to drive ~25% production growth in 2018 with free cash flow generation in 2H % 2018e Crude Oil Corporate Responsibility focused on sustainable operations and the safe and responsible development of our assets May

4 PDC ENERGY Company Overview $3.9B Market Cap (1) $5.1B Enterprise Value (1) 453 YE17 Proved Reserves Core Wattenberg ~100,000 net acres (2) 1,500 identified locations (2) 351 MMBoe proved reserves Delaware Basin ~60,000 net acres (3) 450 identified locations (4) 98 MMBoe proved reserves (1) As of 5/8/18; assumes 66 mm shares outstanding; (2) Niobrara and Codell only. Includes Bayswater acquisition locations; (3) Includes ~3,200 net acres in Western area due to May 2018 expire in 1H18; (4) Some locations subject to higher degree of uncertainty as they are based on downspacing tests the Company is currently in process of testing or has not yet tested. 4

5 PDC ENERGY Track Record of Delivering Value Proven track record of value-added growth 35+% 3-year production CAGR 50 Production (MMBoe) 40 Remain focused on balance sheet strength ~40% decrease in debt per flowing Boe since 2016 Delaware Basin acquisition YE18e leverage ratio of 1.3x 19-22% 42-45% e $25,000 Debt per Flowing Boe 32-35% 500 Proved Reserves (MMBoe) $20, $15, $10, $5, e May

6 PDC ENERGY Portfolio Value Creation Robust inventory of years at current development pace Entire portfolio delivers strong economic results Weighted-average portfolio of MRL equivalents delivers F&D costs of < $8/Boe and IRRs of ~70% XRL development further strengthens expected IRRs & NPVs Additional upside potential to current well performance Early-stage development in the Delaware Prairie and Plains Areas based on industry data MRL Equivalent Inventory Breakdown (~1,950 total locations) ~150 ~250 ~225 (2) ~650 ~400 ~275 Kersey Plains Prairie Block 4 North Central Other $10.0 $8.0 $9.3 Average NPV10 per well by Area (MRL Equivalent) $8.6 millions $6.0 $4.0 $2.0 $0.0 IRR > 50% IRR > 40% $4.4 Block 4 North Central Kersey Plains Prairie $3.2 $2.1 IRR > 100% IRR > 60% IRR > 60% (1) Economics assume current basin differentials curve applied to NYMEX forecast of approximately $62/Bbl and $2.85/Mcf for 2018; $55/Bbl and $2.75/Mcf in 2019+; excludes lease acquisition and May 2018 corporate level costs. Target MRL CWC approximately $3.5 million in Wattenberg and $11 million in Delaware; (2) Approximately 175 Wattenberg and 50 Delaware MRL equivalent locations. 6

7 PDC ENERGY 2018 Financial Guidance Reaffirmed $ Guidance Production: 38 42MMBoe Capital Investments: $850 - $920MM Price Realizations (% NYMEX) (excl. TGP) Oil: 91 95% Gas: 55 60% NGL: 30 35% TGP/Boe 2018e Commodity Mix 19-22% 32-35% 42-45% $4.00 $3.00 $2.00 $1.00 $- $8.00 LOE/Boe G&A/Boe $ $3.00 $1.00 $ $0.80 Oil Natural Gas NGLs $6.00 $4.00 $ $3.70 $0.50 $2.00 $ e $ e May

8 PDC ENERGY Overview of Financial Strength Leverage ratio of 1.7x $745 million liquidity Leverage and Liquidity $1,000 Debt Maturity Schedule (millions) $45 million cash balance Anticipate exiting 2018 with an undrawn revolver 2018e outspend reduced from ~$90 to ~$65 million due to combination of pricing and performance to-date 100% of projected outspend is anticipated to be covered by proceeds from Utica divestiture and SaddleButte transaction (~$65 million) $750 Undrawn Revolver 5.75% Senior Notes Hedge Portfolio ~70% of 2Q-4Q18e oil production hedged at ~$51.50/Bbl (1) $ % Senior Notes ~1.5 MMBbls of Midland basis swaps at ($0.10/Bbl) 8.2 MMBbls 2019 oil hedged at ~$53/Bbl (1) ~70% of 2Q-4Q18e gas production hedged at ~$2.95/MMBtu (1) $ % Convertible Notes Weighted-avg. basis swap of ~($0.45/MMBtu) on ~65% of 2Q-4Q18e gas Began layering in 2019 gas hedges at ~$2.75/MMBtu $ (1) Assumes weighted-average floor prices May

9 PDC ENERGY Corporate Social Responsibility SAFE OPERATIONS EMPLOYEES MATTER COMMUNITY OUTREACH May

10 PDC ENERGY Expect Strong Balance Sheet with Capital Efficient Growth 80 Production and Leverage Ratio Outlook 4.0x Capital efficient production growth 3-Year Production CAGR estimated at ~33% Targeting 30 40% production growth in 2019 Projected YE19 Leverage Ratio of ~1.0x 2018 expected outspend covered by Utica divestiture and Saddlebutte proceeds Anticipate a build in FCF of $100-$200MM in 2019 MMBoe Production Range Leverage Ratio e 2019e 3.0x 2.0x 1.0x 0.0x Leverage Ratio Based on six rig pace through in Wattenberg and 3 in Delaware e (1) 2019e YE Leverage Ratio ~1.9x ~1.3x ~1.0x Capital Investment (MM) $790 $850 - $920 $950 - $1,050 (Outspend)/FCF ($211mm) (~$65mm) ~$100 - $200mm Production Profile % growth Rig Program (WB/DE) 3/3 3/3 3/3 NYMEX Prices ($/Bbl / $/Mcf) ~$51/$3 $62/$2.85 $55/$3 (1) Includes 1Q18 actual results and updated pricing and basis differential assumptions to FY18 outlook. May

11 ASSET OVERVIEW

12 CORE WATTENBERG Prolific Asset in Development Mode 100,000 1Q18 Results 76,625 Boe/d 35 Spuds 29 TILs ~Net Acres (1) 1,500 ~Horizontal Locations (2) 351 YE17 Proved Reserves (MMBoe) (1) Niobrara and Codell only; (2) Includes Bayswater acquisition locations. May

13 CORE WATTENBERG 2018 Activity Focused on Capital Efficient Development Plan to invest $470 - $500 million in 2018 Expect to spud and TIL wells Plan to operate three rigs and one completion crew (1) Majority of focus in prolific Kersey Area Initial Prairie wells to be evaluated in reduced line pressure environment Sequential growth expected through remainder of 2018 as midstream expansion comes online Average working interest for 2018 TILs expected to be 85+% Focus on maintaining low cost structure Anticipate 2018e LOE/Boe of $ $2.75 Recent Saddle Butte pipeline agreement delivers ~$24 million in proceeds, strengthens commitment to move more oil volumes on pipe, additional acres dedicated all numbers approximate SRL MRL XRL Lateral length (feet) 4,200 6,900 9,500 Drilling Days (spud-to-spud) % of 2018 spuds 25% 45% 30% % of 2018 TILs 50% 35% 15% Completed well cost (millions) $2.6 $3.5 $4.4 (1) Second crew scheduled to complete one pad in 2Q18 May

14 CORE WATTENBERG Production Unbundled with Midstream Expansions Wattenberg production expected to account for ~75-80% of 2018e volumes Natural Gas DCP gathers and processes ~75% of Wattenberg gas DCP system throughput capacity expected to increase by ~50% in next 12 months (1) Plant 10 (200 mmcf/d) expected TIL in August 2018 Plant 11 (200 mmcf/d mmcf/d bypass) expected TIL 2Q19 Plant 12 (up to 1 Bcf/d including bypass) initial TIL expected 2020 ~25% of 2018e gas to Aka Energy Oil Recently executed long-term firm transportation commitment with Tallgrass Energy 12,500 Bbls/d with access to refinery destinations and Cushing, OK ~70% of infield oil volumes gathered on pipe (1) Per DCP Midstream earnings call 5/8/18 May

15 DELAWARE BASIN Primary Focus in Two Oil-Rich Areas 60,000 1Q18 Results 20,690 Boe/d 8 Spuds 7 TILs ~Net Acres (1) 450 Est. Block 4 & North Central MRL Locations (2) 98 YE17 Proved Reserves (MMBoe) (1) Includes ~3,200 acres in the Western area due to expire in 1H18; (2) Some locations subject to higher degree of uncertainty as they are based on downspacing tests the Company is May 2018 currently in process of testing or has not yet tested. 15

16 DELAWARE BASIN Focused on Continued Execution Anticipate 2018 capital investments of $380 - $420 million ~75% allocated to spud and TIL operated wells ~15% planned for midstream infrastructure investments ~10% for leasing, non-op and technical studies 25,000 20,000 Delaware Production (Boe/d) 20,690 Drilling and completion execution delivering strong sequential production growth Focus on artificial lift, choke management and infrastructure investment are paying dividends ~135% production growth from 1Q17 to 4Q17 Anticipate FY18 Delaware production to more than double from FY17 Focus on water mgmt. helps deliver low-cost operations 2018 LOE expected to be between $ $4.50/Boe Initial water recycling tests planned mid-year Boe/d 15,000 10,000 5, ,000 12,900 10,000 6,800 5,700 Dec. '16 1Q17 2Q17 3Q17 4Q17 1Q18 May

17 DELAWARE BASIN Prolific Results Continue in Block 4 Buzzard and Grizzly wells continue to show strong early performance (~70% oil) Drilling last two wells on six-well downspacing test Grizzly Bear testing 12 wells per section equivalent spacing in Wolfcamp A Initial Wolfcamp C test drilled (Grizzly West) Hermit Eastern Area Block 4 Kenosha Elkhead Buzzard North 500,000 Wolfcamp A/B XRL Argentine Buzzard South 400, MMBoe EUR Blue Lakes Lost Saddle Grizzly North Boe 300, MMBoe EUR Grizzly Bear (6 Well Downspacing Test) Grizzly South 200,000 Grizzly West 100, Days Buzzard North (A) Buzzard South (B) Grizzly North (B) Grizzly South (A) Approximate Surface Locations Wells Online 2018 Expected TILs May

18 DELAWARE BASIN Solid Early Data from North Central Wells Five 1Q18 TILs in North Central 3-well Greenwich pad, Sunnyside, Old Monarch, Three Wolfcamp A s (2 MRL, 1 SRL) Two Wolfcamp B s ( 1MRL, 1 SRL) North Central Area Sunnyside State Lazy Acre All wells in early flowback stage (< 60 days online) Each well producing an average of ~1,000 1,400 Boe/d (average of all five is ~1,150 Boe/d) Averaging ~55% crude oil Four expected TILs remaining in 2018 Yellow Jacket and Hornet (same pad) Greenwich pad (2-wells) Approximate Surface Locations Greenwich 3H/4H Wells Online Non-Op Well 2018 Expected Activity Yellow Jacket Greenwich (2-well pad) Greenwich (3-well pad) Liam State Hornet Old Monarch May

19 DELAWARE BASIN Oil Marketing Summary Delaware oil production expected to account for 20-25% of total PDC 2018e volumes Oil Gathering Infield oil is piped and trucked to central delivery points ~50% of 2018e oil production is on pipe directly connected with Oryx (10,000 Bbl/d agreement with Oryx Midstream) 2018e investment of ~$20MM in PDC-owned oil gathering system in Block 4 Downstream Marketing Executed firm sales agreement with marketing division of a large, international energy company Provides firm physical takeaway capacity and int l pricing exposure 5.5 year agreement provides flow assurance out of Midland for ~85% of 2018e and 2019e volumes Eliminates majority of exposure to Midland differentials Achieves price diversification by selling at Corpus Christi terminal and realizing international export-market (Brent blend) pricing Anticipate 2018e & 2019e total oil volumes to realize 88-92% NYMEX Source: BTU Analytics Int l Price Exposure May

20 DELAWARE BASIN Gas Gathering Overview Delaware gas production expected to account for ~20-25% of total PDC 2018e gas volumes Eastern Block 4 and South Central Area Eagle Claw Volumes processed by Eagle Claw Midstream and marketed by PDC 100% of current volumes have firm takeaway capacity, including: 40,000 MMbtu/d El Paso transportation to Waha 40,000 MMbtu/d Firm Sale indexed to Houston Ship Channel (HSC) with fixed differential through 2019 Actively working to secure additional firm transportation capacity North Central Area ETC Volumes bought at the wellhead by ETC and marketed on ETC-owned assets Source: BTU Analytics May

21 PDC ENERGY Strategic Overview Returns Results Responsibility e Production (MMBoe) ~$ e Outspend (millions) ~130 Dec. 18e Exit Rate (Mboe/d) 1.3x YE18e Leverage Ratio Strong Returns on inventory ~2,000 gross locations in the Core Wattenberg and Delaware basins Prolific Results expected to drive ~25% production growth in 2018 with free cash flow generation in 2H % 2018e Crude Oil Corporate Responsibility focused on sustainable operations and the safe and responsible development of our assets May

22 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

23 APPENDIX

24 DELAWARE BASIN Water Management Improves Efficiencies Water mgmt. delivers incremental value options Better operational control and synergies Reduced LOE and/or capital per well More than 90% of produced water volumes transported via pipe in 1Q18 Central Area wells utilize PDC water lines and SWDs Completion-Water Distribution System 24 trunk line through center of acreage Capable of delivering enough treated water to support two frac crews Water treatment facility under construction Two treated water pits (375 MBbls capacity per pit) One SWD well in Block 4 (30 MBbls/d capacity) Utilized ~20% recycled water in Kenosha/Elkhead wells Substantial reuse of recycled water planned for completions of Grizzly Bear Pad Eastern Area Block 4 Water Distribution System Hermit Blue Lakes Grizzly Bear (6 Well Downspacing Test) Approximate Surface Locations PDC SWD PDC Planned SWD 3 rd Party SWD Lost Saddle Kenosha Grizzly West Fresh Water Pit Treated Water Pits Argentine Elkhead Grizzly North Grizzly South Buzzard North Buzzard South 24 Water Distr. Line Water Gathering Line May

25 Reconciliation U.S. Non-GAAP Adjusted EBITDAX Three Months Ended March 31, Net income (loss) to adjusted EBITDAX: Net income (loss) $ (13.1) $ 46.1 (Gain) loss on commodity derivative instruments 47.2 (80.7 ) Net settlements on commodity derivative instruments (26.0) 0.5 Non-cash stock-based compensation Interest expense, net Income tax expense (benefit) (4.6) 26.3 Impairment of properties and equipment 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) (3.2) Gain (loss) on sale of properties and equipment (1.4) 0.2 Exploration, geologic, and geophysical expense Other (0.2) (0.7) Changes in assets and liabilities (30.2) (25.8) Adjusted EBITDAX $ $ May

26 Reconciliation U.S. Non-GAAP Adjusted Cash Flows from Operations Three Months Ended March 31, Adjusted cash flows from operations: Net cash from operating activities $ $ Changes in assets and liabilities (30.2) (25.8) Adjusted cash flows from operations $ $ Adjusted Net Income (Loss) Three Months Ended March 31, Adjusted net income (loss): Net income (loss) $ (13.1) $ 46.1 (Gain) loss on commodity derivative instruments 47.2 (80.7) Net settlements on commodity derivative instruments (26.0) 0.5 Tax effect of above adjustments (5.1) 30.0 Adjusted net income (loss) $ 3.0 $ (4.1 ) Weighted-average diluted shares outstanding Adjusted diluted earnings per share $ 0.05 $ (0.06 ) May