2018 SECOND QUARTER EARNINGS CALL. August 9, 2018

Transcription

1 2018 SECOND QUARTER EARNINGS CALL August 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 expect, anticipate, intend, plan, believe, seek, estimate 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 and 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; our 2020 outlook; the impact of potential ballot initiatives and other Colorado political matters; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; timing and likelihood that the Denver Metro/North Front Range NAA ozone classification will be reclassified to serious; and timing and adequacy of infrastructure projects of our midstream providers. The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report 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 report 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, 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. 2

3 BART BROOKMAN President and Chief Executive Officer

4 OPERATIONAL EFFICIENCIES Enhance Near-Term Outlook Total production of 9.4 MMBoe (~103,000 Boe/d) ~20% growth over 2Q17 volumes from Wattenberg and Delaware Oil production of 3.9 MMBbls (~42% of total production) 25% increase over 2Q17 volumes from Wattenberg and Delaware Key Takeaways Continued execution through 2 nd quarter Updated 2018 guidance reflects increased efficiencies and modified cost structure Continued execution in Delaware basin Continued outperformance of Block 4 wells Seven North Central wells TIL d in 1H18 (30-day peak IP averaging 220 Boe/d per 1,000 ; 53% oil) Project FCF generation in 2H18 Strong 2Q18 corporate oil price realizations of 94% of NYMEX drive cash flows Delaware volumes realized 92% of NYMEX in June (firm sales agreement start-up) Recent start-up of DCP Plant 10 (1) offers tremendous 2H18 upside in Wattenberg (1) Source: DCP Midstream press release dated August 1,

5 OPERATIONAL EFFICIENCIES Enhance Near-Term Outlook 2018e production guidance updated to MMBoe Midpoint increased 1 MMBoe from prior guidance Represents year-over-year production growth of 25-30% Maintain 42-45% anticipated oil mix Expected December exit rate increased to ~135,000 Boe/d Operational efficiencies in both basins Wattenberg increase in projected spud count; modified completion design leads to more expected stages per well Delaware modified completion design testing viability of longer stage lengths Anticipated capital investment of $950 - $985 MM Combination of increased efficiencies and service cost pressures Expected FY18 outspend of $75-$100 MM (~$65 MM covered by Utica divestiture and Saddlebutte proceeds) Expect to generate FCF in 2H18 and exit year with undrawn revolver Maintain strong balance sheet with anticipated YE18 leverage ratio of 1.3x 5

6 SCOTT REASONER Chief Operating Officer

7 PDC ENERGY 2018 Second Quarter Overview 103,000 Production (Boe/d) 20% Production Increase (1) (2Q18 v 2Q17) 25% Oil Production Increase (1) (2Q18 v 2Q17) Core Wattenberg 78,300 Boe/d (41% oil) 43 gross operated spuds 48 gross operated TILs ~$145 million capital investments Delaware Basin 24,800 Boe/d (45% oil) 6 gross operated spuds 5 gross operated TILs ~$115 million capital investments (1) Production increase from Wattenberg and Delaware Basin operations, adjusted for Utica asset divestiture 7

8 PDC ENERGY Updated Capital Investment Summary Original Guidance $850 - $920 = Midpoint Well Cost Overview Wattenberg Increased WI Add l Wattenberg Spuds ~$35 ~$25 Drilling efficiencies lead to increased spud count Expect spuds (up from ) Reduction to per well costs Completion efficiencies lead to increased frac stages 10+% increase in stages per well (heal & toe stimulation) DE Midstream Investment ~$15 Increase to per well costs Service cost pressures Well Costs (Service Costs + Comp. Design) 5-10% ~$60 Labor tightness, steel tariffs New per well costs of $3 - $5MM (1) Reduced Leasing, Seismic & Non-Ops (~$55) Delaware Completion modifications lead to fewer frac stages Reduction to per well costs Updated Guidance $950 - $985 $850 $900 $950 $1,000 $1,050 millions Service cost pressures Labor tightness, steel tariffs New per well costs of $10 - $15MM (1) (1) Depending on lateral length 8

9 PDC ENERGY Quarterly Production and LOE Summary Delaware production continues to outperform Wattenberg 2Q production negatively impacted by tough midstream conditions High line pressures, planned & unplanned downtime and hotter than average temperatures Impact to vertical wells and recent horizontal wells Strong sequential growth expected through 2H18 Wattenberg LOE double hit by field-wide midstream environment High line pressures lead to increased costs and decreased production Delaware volumes continue to increase as a percentage of total production Strong well performance and effective water management drive low costs per Boe 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 $2.98 LOE ($/Boe) $2.83 $3.33 $3.44 $ $ ,000 $ Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Dec. '18e all numbers approximate Exit Rate $0.00 1Q17 2Q17 3Q17 4Q17 1Q18 2Q e 9

10 CORE WATTENBERG Add l Productivity Benefits of Consolidated Acreage Modified completion design enhances ability to access additional resource Completing through the bend and drilling to edge of lease boundary enable additional ~1,000 of completed lateral per well Incremental capital of ~$250k per well ~10% additional stages per well expected to be completed in 2018 Example: Prior design 10 well pad of XRLs = ~500 total stages New design 10 well pad of XRLs = ~550 total stages (one extra well) Through the Bend Increased drilling efficiencies lead to improved spud-to-spud times 5/7/9 days for SRL/MRL/XRLs (down from 6/8/10) Drill to Edge ~650 ~1,000 of additional completed interval (5 extra stages) (Wattenberg D&C well costs modified to ~$3 to $5MM depending on lateral length) ~350 10

11 DELAWARE BASIN Continued Execution Boe/d Daily production of ~25,000 Boe/d (45% oil) 20% increase sequentially compared to 1Q18 Delaware accounted for ~25% of PDC corporate volumes 30,000 25,000 Delaware Production (Boe/d) 25,000 Grizzly 8-well pad continues to progress Wolfcamp B and C wells TIL ahead of schedule; currently in flowback stage Wolfcamp A 12-wells per section equivalent downspacing test currently finishing completions 20,000 15,000 13,000 16,000 21,000 Midstream investments providing cost benefits Effectively all produced water volumes on pipe LOE of $3.92/Boe in 2Q18 10,000 5,000 5,700 7,000 10,000 Delaware basin D&C costs modified to ~$10 to $15MM per well depending on zone and lateral length 0 Dec. '16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 all numbers approximate 11

12 Gross 2-Phase Cumulative BOE DELAWARE BASIN Prolific Results Continue in Block 4 Block 4 wells consistently delivering results above internal expectations Recently completed wells averaging ~290 Boe/d per 1,000 (30-day average IP) Anticipate ~90% of Block 4 oil production to-be on PDC oil gathering system at YE18 350, , , , , ,000 Wolfcamp A Average Wolfcamp B Average Block 4 Wolfcamp A/B (7,500' Equivalent) (1) ~2.25 MMBoe EUR ~1.25 MMBoe EUR Approximate Surface Locations Hermit Blue Lakes Grizzly Bear (6 Well Downspacing Test) Eastern Area Block 4 Lost Saddle Grizzly West Kenosha Argentine Elkhead Buzzard North Grizzly North Grizzly South Buzzard South 50, Days Wells Online 2018 Expected Activity Delivery to Oryx (1) Results shown as MRL equivalent to more closely align to our focus area inventory estimate and economics, both of which are also based on MRL equivalents 12

13 DELAWARE BASIN Oil Gathering System Enhances Operational Efficiency Map Reflects Anticipated Oil Gathering System at Year-End 2018 Oil gathering provides significant operational efficiencies Reduced transportation costs compared to trucking Minimal reliance on trucking Reduced facilities on pad Reduced potential emissions from tanks Oil Gathering System Oil gathering lines planned throughout Block 4 acreage Oil treatment facility currently under construction Design supports tankless battery operations Accessibility to downstream pipelines Optionality for expansion Anticipate ~90% of Block 4 oil volumes to be on pipe at YE18 Ten most recent wells on pipe Central Area wells trucked to Oryx delivery points System capable of gathering and treating short- and long-term PDC development Approximate Surface Locations Hermit Blue Lakes Grizzly Bear (6 Well Downspacing Test) Oil Gathering Line Oil Treatment Facility Oryx Delivery Point Eastern Area Block 4 Lost Saddle Grizzly West Kenosha Argentine Elkhead Buzzard North Grizzly North Grizzly South Buzzard South 13

14 Gross 2-Phase Cumulative Boe DELAWARE BASIN North Central Well Results Seven 1H18 TILs in North Central delivering solid results Averaging ~220 Boe/d per 1,000 ~53% oil North Central Area State Lazy Acre Incremental ~$10 MM midstream infrastructure planned in this area to handle outperformance Rabbit Ears Sunnyside (2) Old Monarch Central Area Performance (7,500 Equivalent) Greenwich (2-well pad) 250, ,000 Wolfcamp A/B Avg. Production ~2.0 MMBoe EUR Greenwich (3-well pad) 150,000 Greenwich 3H/4H 100,000 Yellow Jacket 50, Days Approximate Surface Locations Wells Online Non-Op Well 2018 Expected Activity Liam State Hornet 14

15 SCOTT MEYERS Chief Financial Officer

16 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 June 30, % Production (MMBoe) % Realized Price per Boe (excluding derivatives) $34.74 $ % Total crude oil, natural gas and NGLs sales $325.9 $ % Net income (loss) ($160.3) $41.3 * Weighted-average diluted shares outstanding * Earnings per diluted share ($2.43) $0.62 * Net cash from operating activities $175.7 $ % * = Not Meaningful $150 $ Q17 3Q17 4Q17 1Q18 2Q18 Production by Basin Wattenberg Utica Delaware 4.0 2Q17 3Q17 4Q17 1Q18 2Q18 16

17 millions millions FINANCIAL RESULTS Summary Non-U.S. GAAP See Appendix for Reconciliation $250 Adjusted EBITDAX (1) MK Note Proceeds ($40.2 mm) Measure (1) (millions except per share data) Three Months Ended June 30, % Adjusted net income (loss) (2) ($84.5) $12.5 * Adjusted earnings per diluted share ($1.28) $0.19 * $200 $150 Adjusted cash flows from operations $199.3 $ % $100 2Q17 (3) 3Q17 4Q17 1Q18 2Q18 Adjusted EBITDAX $ % Adjusted EBITDAX per diluted share $3.24 $3.04 7% $250 Adj. Cash Flow from Operations (1) Weighted-average diluted shares outstanding * * = Not Meaningful $200 $150 $100 2Q17 3Q17 4Q17 1Q18 2Q18 (1) See appendix for non-u.s. GAAP reconciliations; (2) Includes 2Q18 impairment of $159.5 million ; (3) Includes $40.2 million of notes receivable proceeds in 2Q17. 17

18 Production Costs (per Boe) Production (MMBoe) FINANCIAL RESULTS Production Cost Summary Measure Three Months Ended June 30, % Production (MMBoe) % Production Costs per Boe vs Production (MMBoe) Operating Costs (millions) $10 10 Lease operating expenses $32.3 $ % Production taxes $22.6 $ % Transportation, processing and gathering $9.0 $6.5 38% $8 $6 8 6 Total $63.9 $ % $4 4 Operating Costs per Boe Lease operating expenses $3.44 $ % $2 2 Production taxes $2.41 $ % Transportation, processing and gathering $0.96 $ % Total per Boe $6.81 $ % $0 2Q17 3Q17 4Q17 1Q18 2Q18 LOE TGP Production Tax Production 0 Lease Operating Expenses by Basin ($/Boe) Wattenberg $3.29 $ % Delaware $3.92 $4.88 (20%) 18

19 FINANCIAL STRENGTH Balance Sheet, Leverage and Liquidity As of June 30, 2018 Leverage ratio of 1.6x Leverage and Liquidity $1,000 Debt Maturity Schedule (millions) $680 million liquidity ~$20 drawn on revolver Anticipate exiting 2018 with an undrawn revolver 2018e outspend of ~$75 - $100 million Utica divestiture and SaddleButte transaction cover ~$65 million Anticipate delivering free cash flow in 2H18 $750 Undrawn Revolver 5.75% Senior Notes Hedge Portfolio $ % Senior Notes ~70% of 2H18e oil production hedged at ~$51/Bbl (1) 9.8 MMBbls 2019 oil hedged at ~$54/Bbl (1) ~65% of 2H18e gas production hedged at ~$2.95/MMBtu (1) $ % Convertible Notes Weighted-average basis swap of ~($0.43/MMBtu) on ~55% of 2H18e gas Began layering in 2019 and 2020 hedges $ (1) Assumes weighted-average floor prices 19

20 FINANCIAL GUIDANCE Updated Full-Year Guidance $ Guidance Production: 40 42MMBoe Capital Investments: $950 - $985MM Price Realizations (% NYMEX) (ex. 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 $ $3.15 $1.00 $ $0.90 Oil Natural Gas NGLs $6.00 $4.00 $ $3.70 $0.50 $2.00 $ e $ e 20

21 LANCE LAUCK EVP Corporate Development & Strategy

22 CORE WATTENBERG Production Unbundled with Midstream Expansions DCP Midstream (~75% of 2018e gas volumes) Plant 10: In-service August 1, 2018 (1) Increases system throughput 200 MMcf/d or ~25% Anticipate maintaining current share of DCP system Plant 11: 300 MMcf/d (including bypass) Expected start-up in 2Q19 Grand Parkway Plant 12: Up to 1 Bcf/d (including bypass) Expected start-up in 2020 Aka Energy (~25% of 2018e gas volumes) Recently expanded processing capacity to ~40 MMcf/d Additional offloads to WES system Other DJ Basin Anticipated Expansions Plant 10 Plant 11 Rimrock, Discovery, Western Gas, Outrigger (~1 Bcf/d additional capacity) expected to benefit entire basin DCP - Aka - Additional compression Compression Processing Plant Expansions Processing Plant (1) Source: DCP Midstream press release dated August 1,

23 DELAWARE BASIN Significant Flow Assurance with Competitive Pricing Delaware oil and gas production expect to account for ~20-25% of total PDC 2018e volumes Oil Downstream Marketing Gulf Coast 5.5 year firm sales agreement effective in June 2018 International export-market pricing Anticipate competitive netback pricing relative to Mid-Cush through entire contract term Near-term impact (2H ) Covers ~85% of projected Delaware volumes with remaining ~15% sold at Midland Project all-in Delaware realizations of 88-92% NYMEX (June 2018 = ~92% NYMEX) Gas Processing & Marketing 100% of current Eastern volumes have firm takeaway: Firm transport to Waha with associated firm sales agreements (indexed to Gulf Coast prices) Contracts ramping to total of ~75,000 MMBtu/d N. Central volumes sold at wellhead to ETC and marketed on ETC-owned assets (Waha) 23

24 DELAWARE BASIN MIDSTREAM Potential Value Creation Initiated formal process to evaluate a potential strategic midstream asset transaction Includes infield oil and gas gathering, gas compression, water gathering and disposal and future gas processing Retained Jefferies as exclusive financial advisor Infrastructure investments since acquisition (4Q16): Oil gathering & treatment system in Block 4 of Eastern Area Gas and water gathering lines throughout position SWD wells throughout position Water management system PDC Owned Gathering Lines Oil Gas Water Potential value-creating outcomes for PDC Full or partial monetization of assets Joint Venture Retain 100% ownership of assets 24

25 MMBoe Leverage Ratio 2020 OUTLOOK Anticipate Strong Growth & Free Cash Flow Generation. Steady-state 6 Rig Scenario Capital efficient production growth 3-Year Production CAGR estimated at nearly 30% 2020 exit rate of approximately ~200,000 Boe/d Production and Leverage Ratio Outlook (6 Rig Scenario) Production Leverage Ratio 4.0x 3.0x Project to build more than $400 million in cumulative free cash flow from 2H x Operational Assumptions 3 rigs in Wattenberg and 3 rigs in Delaware for all years One full-time completion crew in each basin (2 nd crew planned in Wattenberg for part of 2020) $50MM of Delaware midstream investment both 2019 and 2020 Includes updated well costs and current widened differentials Potential 2020 Considerations Addition of 4 th rig in Delaware and/or additional Wattenberg completions Key factors: pricing, differentials, marketing/midstream, service costs, etc x 0 0.0x e 2019e 2020e 3 Rigs in WB and DE 2018e 2019e 2020e YE Leverage Ratio ~1.3x ~1.0x ~0.8x Capital Investment (MM) $950 - $985 $950 - $1,050 $1,000 - $1,200 Production Profile (MMBoe) % growth (Outspend)/FCF (MM) ($75 - $100) $100 - $200 $200 - $300 Cash Flow Yield (1) (8%) 10-20% 20-25% NYMEX Prices ($/Bbl / $/Mcf) ~$65/$2.75 $65/$2.75 $60/$2.75 (1) Cash flow deficit/free cash flow divided by midpoint of total capital investment 25

26 QUESTIONS & ANSWERS

27 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

28 APPENDIX

29 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,

30 Reconciliation of Non-U.S. GAAP Financial Measures Adjusted EBITDAX Three Months Ended June 30, Six Months Ended June 30, Net income (loss) to adjusted EBITDAX: Net income (loss) $ (160.3) $ 41.2 $ (173.4) $ 87.4 (Gain) loss on commodity derivative instruments (57.9) (138.6) Net settlements on commodity derivative instruments (16.4) 12.0 (42.4) 12.5 Non-cash stock-based compensation Interest expense, net Income tax expense (benefit) (45.3) 24.5 (49.9) 50.9 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 (3.1) (3.2) (6.4) (6.4) Gain (loss) on sale of properties and equipment (1.1) 0.7 Exploration, geologic and geophysical expense Other (0.5) 40.3 (0.6) 39.6 Changes in assets and liabilities (6.6) (15.8) Adjusted EBITDAX $ $ $ $

31 Reconciliation of Non-U.S. GAAP Financial Measures Adjusted Cash Flows from Operations Adjusted cash flows from operations: Three Months Ended June 30, Six Months Ended June 30, Net cash from operating activities $ $ $ $ Changes in assets and liabilities (6.6) (15.8) Adjusted cash flows from operations $ $ $ $ Adjusted Net Income (Loss) Adjusted net income (loss): Three Months Ended June 30, Six Months Ended June 30, Net income (loss) $ (160.3) $ 41.2 $ (173.4) $ 87.4 (Gain) loss on commodity derivative instruments (57.9) (138.6) Net settlements on commodity derivative instruments (16.4) 12.0 (42.4) 12.5 Tax effect of above adjustments (23.9) 17.2 (29.0) 47.2 Adjusted net income (loss) $ (84.5) $ 12.5 $ (81.4) $ 8.5 Weighted-average diluted shares outstanding Adjusted diluted earnings per share $ (1.28) $ 0.19 $ (1.23) $