2018 THIRD QUARTER EARNINGS CALL. November 6, 2018

Transcription

1 THIRD QUARTER EARNINGS CALL 6,

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 presentations are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; management of lease expiration issues; financial ratios and compliance with covenants in our revolving credit facility; impacts of certain accounting and tax changes; midstream capacity and related curtailments; fractionation capacity; impacts of Proposition 112 and other Colorado political matters; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; reclassification of the Denver Metro/North Front Range NAA ozone classification to serious; and timing and adequacy of infrastructure projects of our midstream providers, including the impact of having a new plant come online during the third quarter of. The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this presentation reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this presentation or accompanying materials, we may use the term projection 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 our 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, and amended on May 1,, 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 WCA/WCB/WCC Wolfcamp A/Wolfcamp B/Wolfcamp C PDC Energy, Inc. All Rights Reserved. 2

3 BART BROOKMAN President and Chief Executive Officer

4 SOLID EXECUTION Begins Unlocking Potential Total production of 10.1 MMBoe (~110,000 Boe/d) 21% growth over 3Q17 volumes from Wattenberg and Delaware 6% sequential growth over 2Q18 daily volumes Oil production of 4.3 MMBbls (~43% of total production) 27% increase over 3Q17 volumes from Wattenberg and Delaware Oil realizations of ~95% of NYMEX pricing, including 94% of NYMEX on Delaware volumes Wattenberg volumes beginning to benefit from third-party processing capacity expansions Maintained expected system allocations (> 25%) through ramp-up period 2H18 volumes negatively impacted by pace of system optimization Key Takeaways Project free cash flow in 4Q18 Prop 112 outcome not currently expected to materially impact 2019 outlook Anticipate exiting with ~200 approved permits and ~100 DUCs in Wattenberg Wattenberg production starting to benefit from DCP Plant 10; anticipate further performance uplift from Plant 11 in 2019 TIL d 6-well Grizzly Bear downspacing test Initial results support 12 wells per section spacing assumption in Block 4 Wolfcamp A Wolfcamp C production below internal expectations through flowback phase 4

5 SCOTT MEYERS Chief Financial Officer

6 FINANCIAL RESULTS Summary U.S. GAAP millions MMBoe $250 Net Cash from Operating Activities $200 Measure (millions except per share and price per Boe data) Three Months Ended September 30, 2017 % Production (MMBoe) % Realized Price per Boe (excluding derivatives) $36.88 $ % Total crude oil, natural gas and NGLs sales $372.4 $ % Net income (loss) ($3.4) ($292.5) * General & Administrative Expense (1) $48.2 $ % Weighted-average diluted shares outstanding * Earnings per diluted share ($0.05) ($4.44) * Net cash from operating activities $197.0 $ % * = Not Meaningful $150 $ Q17 4Q17 1Q18 2Q18 3Q18 Production by Basin Wattenberg Utica Delaware 4.0 3Q17 4Q17 1Q18 2Q18 3Q18 (1) Includes legal-related costs of $8.0 million 6

7 millions millions FINANCIAL RESULTS Summary Non-U.S. GAAP See Appendix for Reconciliation $250 Adjusted EBITDAX (1) Measure (1) (millions except per share data) Three Months Ended September 30, 2017 % Adjusted net income (loss) $31.8 ($253.9) * Adjusted earnings per diluted share $0.48 ($3.85) * $200 $150 Adjusted cash flows from operations $201.1 $ % $100 3Q17 4Q17 1Q18 2Q18 3Q18 Adjusted EBITDAX $213.2 $ % Adjusted EBITDAX per diluted share $3.23 $ % $250 Adj. Cash Flow from Operations (1) Weighted-average diluted shares outstanding * * = Not Meaningful $200 $150 $100 3Q17 4Q17 1Q18 2Q18 3Q18 (1) See appendix for non-u.s. GAAP reconciliations. 7

8 FINANCIAL RESULTS Production Cost Summary Production Costs (per Boe) LOE/Boe ($/Boe) Production (MMBoe) Measure Three Months Ended September 30, 2017 % Production (MMBoe) % $8 $6 $4 Production Costs per Boe vs Production (MMBoe) Operating Costs (millions) Lease operating expenses $33.0 $ % Production taxes $24.0 $ % Transportation, processing and gathering $9.2 $9.8 (6%) $2 $0 3Q17 4Q17 1Q18 2Q18 3Q18 LOE TGP Production Tax Production 6 4 Total $66.2 $ % Operating Costs per Boe Lease operating expenses $3.27 $ % $6 LOE per Boe by Basin ($/Boe) Production taxes $2.37 $ % Transportation, processing and gathering $0.91 $1.15 (21%) $4 Total per Boe $6.55 $ % Lease Operating Expenses by Basin ($/Boe) $2 Wattenberg $3.01 $ % Delaware $4.09 $6.07 (33%) $0 3Q17 4Q17 1Q18 2Q18 3Q18 Wattenberg Delaware Total Company 8

9 FINANCIAL STRENGTH Balance Sheet, Leverage and Liquidity As of September 30, Leverage ratio of 1.6x Leverage and Liquidity ~$75 million drawn on revolver (9/30/18) October upsized commitment level on revolving credit facility to $1.3 billion from $700 million Pro forma liquidity of $1.23 billion Anticipate delivering free cash flow in 4Q18 $1,500 $1,250 $1,000 Debt Maturity Schedule (millions) Revolver (2) Hedge Portfolio ~60% of 4Q18e oil production hedged at ~$51/Bbl (1) 11.0 MMBbls 2019 oil hedged at ~$55/Bbl (1) 8.6 MMBbls 2020 oil hedged at ~60/Bbl (1) $750 $500 $ % Convertible Notes 6.125% Senior Notes 5.75% Senior Notes ~70% of 4Q18e gas production hedged at ~$2.95/MMBtu (1) $ (1) Assumes weighted-average floor prices; (2) Pro forma October commitment level increase 9

10 FINANCIAL GUIDANCE Updated Full-Year Guidance $1.50 Guidance (1) Production: MMBoe Capital Investments: $950 - $985MM Price Realizations (% NYMEX) (ex. TGP) Oil: 91 95% Gas: 55 60% NGL: 30 35% TGP/Boe e Commodity Mix 19-22% 32-35% 42-45% $4.00 $3.00 $2.00 $1.00 $- $8.00 LOE/Boe G&A/Boe (2) $ $3.15 $1.00 $ $0.90 Oil Natural Gas NGLs $6.00 $4.00 $ $3.70 $0.50 $2.00 $ e $ e (1) Primarily due to the pace of ongoing third-party system optimization negatively impacting 2H18 production, PDC anticipates being at the low-end of the production range, or approximately 40 MMBoe, and at or slightly above the top end of the per Boe cost ranges. (2) G&A per Boe excludes $8 million of legal-related costs incurred in 3Q18. 10

11 MMBoe Leverage Ratio 2020 OUTLOOK Prioritizing Free Cash Flow & Debt-Adj. Per Share Growth Steady-State 6 Rig Scenario 2019 Considerations Do not currently anticipate Proposition 112 outcome to materially impact 2019 outlook ~200 approved permits and ~100 DUCs anticipated at YE Production and Leverage Ratio Outlook (6 Rig Scenario) Production Leverage Ratio 4.0x 3.0x Anticipate Plant 11 providing relief to core DJ acreage (Kersey/Plains) in 2H x Rig count in one or both basins could change post- election x Assume sufficient NGL takeaway and fractionation space for PDC volumes through third-party providers e 2019e 2020e 0.0x 3 Rigs in WB and DE e 2019e 2020e 2020 Considerations Capital allocation in both basins dependent on CO political landscape Key factors: pricing, differentials, marketing/midstream, service costs, downspaced well performance, etc. YE Leverage Ratio ~1.4x ~1.0x ~0.8x Capital Investment (MM) $950 - $985 $950 - $1,050 $1,000 - $1,200 Production Profile (MMBoe) ~40 (2) 25 35% 15 25% growth (Outspend)/FCF (MM) ($ ) $100 - $200 $200 - $300 Cash Flow Yield (1) (14%) 10-20% 20-25% NYMEX Prices ($/Bbl / $/Mcf) ~$70/$3.00 (3) $65/$2.75 $60/$2.75 (1) Midpoint of cash flow deficit/free cash flow divided by midpoint of total capital investment; (2) Anticipate at the low-end of the range of MMBoe; (3) 4Q18 internal pricing 11

12 SCOTT REASONER Chief Operating Officer

13 PDC ENERGY Third Quarter Overview 110,000 Production (Boe/d) 21% Production Increase (1) (3Q18 v 3Q17) 27% Oil Production Increase (1) (3Q18 v 3Q17) Core Wattenberg ~100,000 net acres 83,670 Boe/d (42% oil) 43 spuds & 22 TILs ~$127 million capital investments Delaware Basin ~55,000 net acres (2) 26,110 Boe/d (43% oil) 8 spuds & 10 TILs ~$145 million capital investments (1) Production increase from Wattenberg and Delaware Basin operations, adjusted for Utica asset divestiture; (2) Anticipate ~13,000 net acres (primarily in Western Culberson County) to expire by end of 1Q19. Acreage expirations are not expected to materially impact currently identified inventory. 13

14 PDC ENERGY Quarterly Production and LOE Summary Wattenberg 3Q production beginning to unbundle despite only modest line pressure improvements PDC system allocations maintained through DCP system expansion Aka Energy provides material processing and offloads Strong sequential growth expected in 4Q18 December exit rate of ~130,000 Boe/d Wattenberg LOE projected to decline as production volumes increase Line pressures remain elevated heading into shoulder season and winter Delaware TILs in late 3Q expected to lead to strong 4Q18 growth 150, ,000 73,900 Production (Boe/d) 88,100 92,500 94,100 99, , ,000 $4.00 $3.00 $2.00 $2.98 $2.50 Total Company LOE ($/Boe) $2.98 $2.83 $3.33 $3.44 $ ,000 $ Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 $0.00 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 all numbers approximate 14

15 Avg. Kersey Line Pressure (psi) MIDSTREAM INITIATIVES Projected to Unlock Incremental Value PDC Gross Gas on DCP (MMcf/d) 400 Wattenberg Volumes Steady volume growth with DCP Plant 10 start-up Pace of DCP system optimization, including planned/unplanned downtimes, factored into updated FY18 guidance Consistent run-time benefits core acreage line pressures and PDC volumes PDC Volumes vs Kersey Line Pressure 300 Potential Delaware Midstream Asset Monetization Process ongoing led by Jefferies Evaluating option to keep or sell any or all of PDC s midstream assets, including: Gas gathering and future gas processing Oil gathering and infrastructure Water gathering, disposal and recycling system All midstream infrastructure related to SWD wells 350 Anticipated cumulative capital investment through YE18 estimated at ~$150 million 300 Plant 10 Start-Up Consistent Throughput /1/ 8/1/ 9/1/ 10/1/ 11/1/ Targeting YE18 or 1Q19 decision point Kersey Line Pressure PDC Volumes 15

16 DELAWARE BASIN Initial Grizzly Bear Results Support WCA Inventory Six WCA wells (12 wells/section eq.) showing minimal signs of communication through choke mgmt. tests (~75% oil) Performance and pressure characteristics consistent with low GOR area of Block 4 Ongoing technical analysis valuable for future completion designs and downspacing projects WCC well performance below internal expectations Approximate Surface Locations Hermit Eastern Area Block 4 Kenosha Elkhead Buzzard North Buzzard South Wolfcamp X/Y Wolfcamp A Wolfcamp B Wolfcamp C ½ Section ~80 ~385 Maroon Well (2016) ~280 ~340 ~140 Blue Lakes Lost Saddle Grizzly Bear Pad Maroon Well (2016) Argentine Grizzly West Grizzly North Grizzly South 2019 Initiatives: Bone Spring test, stack spacing test in WCA and WCB, WCC test Wells Online Delivery to Oryx 16

17 DELAWARE BASIN North Central Well Results development plan successful step in delineated North Central Focus Area 13 spuds and 10 TILs throughout position North Central Area State Lazy Acre Eight YTD TILs in North Central area Average 30-day peak IP >200 Boe/d per 1,000 ~50% oil Rabbit Ears Sunnyside (3) 2 Greenwich (2-well pad) Old Monarch TIL program complete Rabbit Ears TIL d in 3Q18 Two Sunnyside wells TIL d in October Greenwich (3-well pad) North Central compression increased in 3Q18 Working on permanent expansions to both compression and pipeline capacity in 4Q18 Approximate Surface Locations TILs Non-Op Well DUCs Yellow Jacket Liam State Hornet 1 17

18 QUESTIONS & ANSWERS

19 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

20 APPENDIX

21 COLORADO POLITCAL UPDATE Proposed 2,500 Setback Details No New Oil & Gas Development Within 2,500 of Occupied Structures and Broadly Defined Vulnerable Areas Industry Viewpoint Confident resources are in place to defeat this initiative WELD Industry s campaign is ongoing, sophisticated, robust, well-organized and well-funded Continued public awareness emphasizing safety and industry is highly regulated in Colorado Greater business-community united with oil & gas industry Differences from 2016 Excludes federal lands from the setback Statutory (not Constitutional) initiative WELD COUNTY: 85% of non-federal land off limits. (All green and yellow areas would be off-limits for future development.) Map and statistics via COGCC Impact Assessment July 2, 21

22 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 $ (3.4) $ (292.5) $ (176.8) $ (205.1) (Gain) loss on commodity derivative instruments (86.5 ) Net settlements on commodity derivative instruments (48.1 ) 9.6 (90.5) 22.2 Non-cash stock-based compensation Interest expense, net Income tax expense (benefit) (3.9 ) (122.4) (53.8) (71.5 ) 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 (3.1) (3.2) (9.5) (9.6) Gain (loss) on sale of properties and equipment (2.1) 0.1 (3.2) 0.8 Exploration, geologic and geophysical expense Exploratory dry hole costs (41.2) (41.2) Other (1.1) (0.4) (1.5) 39.2 Changes in assets and liabilities (2.5) (13.1) Adjusted EBITDAX $ $ $ $

23 Reconciliation of Non-U.S. GAAP Financial Measures 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 (2.5) (13.1) Adjusted cash flows from operations $ $ $ $ Adjusted Net Income (Loss) Three Months Ended September 30, Nine Months Ended September 30, Adjusted net income (loss): Net loss $ (3.4) $ (292.5) $ (176.8) $ (205.1) (Gain) loss on commodity derivative instrument s (86.5 ) Net settlements on commodity derivative instruments (48.1 ) 9.6 (90.5) 22.2 Tax effect of above adjustments (11.1 ) (23.2) (40.1) 24.0 Adjusted net income (loss) $ 31.8 $ (253.9) $ (49.6) $ (245.4 ) Weighted-average diluted shares outstanding Adjusted diluted earnings per share $ 0.48 $ (3.85) $ (0.75) $ (3.73 ) 23