August 26, 2015 HEIKKINEN ENERGY CONFERENCE

Transcription

1 August 26, 2015 HEIKKINEN ENERGY CONFERENCE

2 Forward Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding PDC s business, financial condition, results of operations and prospects. All written or oral statements other than statements of historical facts included in this presentation are forward-looking statements. Words such as expects, anticipates, intends, plans, believes, seeks, estimates, guidance, forecast, outlook and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated future production (including the components of such production), sales, expenses, cash flows and liquidity; estimated crude oil, natural gas and natural gas liquids ( NGLs ) reserves; expected 2015 capital forecast allocations, including revised capital and production forecasts; anticipated increased 2015 capital projects, expenditures and opportunities; the impact of prolonged depressed commodity prices; potential future impairments; availability of sufficient funding for our 2015 capital program and sources of that funding; future exploration, drilling and development activities; including our expected rig count; expected cash flow neutrality in 2H 2015 and 2016; potential additional revisions to our 2015 capital and production forecast; anticipated reductions in our 2015 cost structure; the expiration of certain significant and insignificant leases in the Utica Shale; our evaluation method of our customers' and derivative counterparties' credit risk; our expected positive net settlements on our derivative positions in 2015; effectiveness of our derivative program in providing a degree of price stability; the impact of high line pressures and the timing, availability, cost and effect of additional midstream facilities and services going forward; expected differentials; compliance with debt covenants; expected funding sources upon conversion of our 3.25% convertible senior notes due 2016; the impact of litigation on our results of operations and financial position; that we do not expect to pay dividends in the foreseeable future; and our future strategies, plans and objectives. The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements made in this presentation reflect PDC s good faith judgment, such statements can only be based on facts and factors currently known to PDC. 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, we use the terms outlook, 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 the industry in periods beyond the current fiscal year. In addition to being subject to additional levels of uncertainty generally, forward-looking statements regarding such prospective matters do not necessarily reflect the outcomes we view as the most likely to occur, but instead are shown to illustrate aspects of our business in the context of a variety of scenarios we believe to be plausible. PDC urges you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in the Company s Annual Report on Form 10-K for the year ended December 31, 2014 and PDC s other filings with the U.S. Securities and Exchange Commission ( SEC ), which are incorporated by this reference as though fully set forth herein, for further information on risks and uncertainties that could affect the Company's business, financial condition, results of operations and cash flows. The Company cautions you not to place undue reliance on forward-looking statements, which speak only as of the date hereof. PDC undertakes 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. Before tax PV-10 is a non-gaap measure and is different than the standardized measure of discounted future net cash flows ( standardized measure ), which measure is presented in PDC s Annual Report on Form 10-K dated December 31, 2014, in that before tax PV-10 is a pre-tax number, while standardized measure includes the effect of estimated future income taxes. 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, including our 2P reserves numbers presented herein PDC Energy, Inc. All Rights Reserved. 2

3 PDC Energy High Quality Assets Company Highlights Core Wattenberg Market Cap: ~$2.1 Billion (1) Enterprise Value: ~$2.6 Billion (1) YE 2014 proved reserves 250 MMBoe 64% liquids, 30% proved developed Stress tested to $50/Bbl only 9% lost YE P reserves 667 MMBoe 2P Locations: ~2,700 in Wattenberg and Utica Utica 2015 capital expenditure guidance - ~$535 MM 93% Wattenberg 2015 production guidance: 14.7 to 15.0 MMBoe 40,275 41,100 Boe/d (1) As of August 11, 2015; Approximately 40 million shares outstanding 3

4 PDC Energy Updated 2015 Full-Year Guidance Production forecast: 14.7 to 15.0 MMBoe 60% increase from 2014 continuing operations 65% liquids mix; 47% oil Increased from 13.5 to 14.5 MMBoe primarily due to drilling efficiencies Reduce rig count from five to four in late Category (Mid-Point) Apr 9, 2015 Aug 10, 2015 Capex ($MM) $473 $535 NYMEX prices ($/Bbl & $/MMBtu) $51.72 & $2.86 $51.21 & $2.83 Cash Flow ($MM) ~$365 ~$410 Strong cash flow growth $410 million at mid-point Estimated year-end 2015 Debt to EBITDAX of ~1.5x 2015 capital program of ~$535MM 30% increase in drilling efficiencies; wells spud increased to ~155 from 119 Reduced completed well costs ~28% (SRL) & ~25% (ERL) from 2014 levels $3.1 million (SRL) and $4.1 (ERL) million cost per well Outspend ($MM) ~$110 ~$125 YE 15 Debt/EBITDAX Production (MMBoe) Great position heading into 2016 Second half 2015 expected to be cash flow neutral using July 27, 2015 strip pricing Target to operate 2016 at cash flow neutral level with ~35% production growth Mark-to-market value of hedge portfolio exceeds $250 million using July 27, 2015 strip ~2.0x 13.5 to 14.5 ~1.5x 14.7 to 15.0 Liquid Mix 65% 65% 4

5 Feet PDC Energy Realized Drilling Efficiencies Current Outlook 2015 Analyst Day Average Ft./Day Drilled 1,200 1, Analyst Day 2015 Current Wattenberg SRL Spud to TD: TD to Rig Release: Rig Move: Days Current practices improving drilling time: New automated drillings rigs ( ADR ) able to minimize downtime Drilling team cohesion/personnel Utilizing analytics to improve drilling efficiencies Currently drilling wells at a pace ~30% faster than 2014 Rigs 5 rigs are currently drilling wells at a 2014 ~7 rig pace 2014 Drilling Pace Current 2015 Drilling Pace wells ~140 wells wells ~175 wells wells ~210 wells wells ~245 wells 5

6 PDC Energy Delivering Value Through Execution VALUE DRIVER 2015 Guidance 2016 Outlook PRODUCTION GROWTH ~60% ~35% DRILLING EFFICIENCIES 14+ days spud-to-spud 10 or less days spud-to-spud HIGH-RETURN PROJECTS ~30-60% IRRs on 2015 drilling at $50 oil 1,000+ locations with 50+% IRRs at $60 oil FINANCIAL STRENGTH 2015 YE Debt:EBITDAX of ~1.5x EXECUTION 2016 YE Debt:EBITDAX of ~1.4x LOW COST STRUCTURE Decrease in LOE of ~15% from 2014 Continued improvement to LOE of ~$3/Boe UPSIDE Plug-n-Perf and AccessFrac results 22- and 26-well downspacing projects 6

7 $MM $MM Boe/d Debt to Adj. EBITDAX PDC Energy Resilient 3-Year Outlook 2016 Convertible Notes assumes principal paid in cash with incremental value settled in shares see slide 28 for assumptions Production 90,000 Analyst Day Updated Base Case 80,000 70,000 60,000 50,000 40, Debt to Adjusted EBITDAX Analyst Day Updated Base Case ~1.5x 1.6x ~1.7x 1.8x ~1.6x 1.7x ~1.4x 1.5x 30,000 20,000 10,000 0 $800 $700 $600 5 Rigs Rigs Analyst Day 6.5 Rigs 4 Rigs CAPEX 8 Rigs Updated Base Case 4-5 Rigs $800 $700 $600 Analyst Day Cash Flow Updated Base Case $500 $400 $300 $200 $100 $500 $400 $300 $200 $100 $ (1) Represents a 3-year CAGR beginning with 2014 s production from continuing operations. $0 7

8 Core Wattenberg Position Summary ~96,000 net acres, ~100% HBP Third largest leaseholder and producer Strong, repeatable, lower risk projects 2,640 total 2P locations Based on ~16 Niobrara &~4 Codell per section ~1,000 locations with >50% IRRs at $60/bbl oil and $3.25/mcf gas flat 2015 drilling program: 5 ADR (1) rigs; reduce to 4 rigs in late 2015 ~155 gross operated wells spud ~125 gross operated TILs (2) 47 extended reach laterals spud Testing 22- and 26-well per section equivalents Plug-n-Perf, BioVert (3) and cemented liner testing (1) Automated Drilling Rigs (2) TILs = turn-in-lines; (3) BioVert is a trademark name of Halliburton 8

9 Wattenberg High-Return Projects Throughout Acreage 80% Wattenberg Type Well IRRs (1) 60% 60% 40% 20% 40% 36% 31% 25% 18% 0% Niobrara - Inner Niobrara - Middle Codell - Middle Niobrara - Middle ERL Niobrara - Outer Codell - Outer 625 MBoe 440 MBoe 440 MBoe 600 MBoe 310 MBoe 310 MBoe AFTER NYMEX Oil Price $50.00 $54.00 $58.00 $60.00 $62.00 $65.00 $65.00 NYMEX Gas Price $3.00 $3.15 $3.30 $3.45 $3.50 $3.50 $3.50 (1) IRRs based on the price deck above; CWC $3.1MM for 4,200 lateral, 20 frac stages; CWC $4.1MM for 6,500 lateral, 32 frac stages; assumes long-term oil differential of $9/Bbl. 9

10 Wattenberg Strong, Repeatable Results Based on Evaluation of Public Production Data (1) ~1,400 industry Hz Niobrara wells included in updated analysis of CO DJ Basin EURs now range from 292 to 630 MBoe in Core Wattenberg (all data normalized to 4,200 standard lateral length) Core Wattenberg P10/P90 EUR variability ratio now ranges from 2.4 to 3.0 (improved consistency in all Core areas) 2015 ANALYSIS 1,400 Wells 2014 ANALYSIS 800 Wells Inner Core Middle Core Outer Core CO DJ Niobrara Outside Core Represents 650+ Hz Niobrara wells Represents 150+ Hz Niobrara wells Inner Core Middle Core Outer Core CO DJ Niobrara Outside Core Represents 1,000+ Hz Niobrara wells Represents 400+ Hz Niobrara wells Area Industry Average 3-Phase EUR EUR Variability (P10/P90) Ratio Area Industry Average 3-Phase EUR EUR Variability (P10/P90) Ratio Inner Core 500 MBoe 2.7 Middle Core 400 MBoe 3.3 Outer Core 285 MBoe 3.6 Non-Core DJ Basin 170 MBoe 19.3 Inner Core 630 MBoe 2.4 Middle Core 460 MBoe 2.7 Outer Core 292 MBoe 3.0 Non-Core DJ Basin 180 MBoe 9.1 (1) Based upon publicly available data as of December 31, 2014 for wells in Colorado with 4+ months of production. Assumes an NGL yield of 90 Bbls/MMcf and a 20% gas shrink factor for all wells. 10

11 Wattenberg Technical Development Progress Current Drilling Rig Location; All projects drilled on 16-wells per section equivalent unless otherwise noted Key Technical Updates: Currently Online - Extended Reach Lateral Projects: Chesnut (Sec. 28): 10 wells Middle Core 20-wells per section equivalent test First flow as of April 27 Chesnut (Sec. 27) 16 wells Middle Core Wells were TIL throughout the month of May Churchill: 8 wells Middle Core Wells were TIL late June / early July Currently Being Completed - Extended Reach Lateral Projects: Bernhardt Farms: 5 wells Middle Core Completed wells, expecting first flow mid/late Q3 Stroh: 8 wells Middle Core Finished drilling, expecting first flow mid/late Q3 Downspacing Projects: Becker Ranch: 19 wells (22-well equivalent) Middle Core Currently drilling, expecting first flow in late Q4 Rieder: 13 wells Middle Core (26-well equivalent) Finished drilling, expecting first flow in mid/late Q4 11

12 Wattenberg 2015 Downspacing Projects 22 Wells/Section 20 Wells/Section Chesnut (2015 TIL) 480-acre unit ERL downspacing test 6,700 laterals 10 wells 5 NIO (64-acre spacing) 5 CDL (64-acre spacing) Becker Ranch (Late 2015 TIL) 320-acre unit Standard lateral downspacing test 4,200 laterals 11 wells 8 NIO (40-acre spacing) 3 CDL (107-acre spacing) Half-Section (2,640 ) Half-Section (2,640 ) 26 Wells/Section Rieder (late 2015 TIL) 320-acre unit Standard lateral downspacing test 4,200 laterals 13 wells 10 NIO (32-acre spacing) 3 CDL (107-acre spacing) Half-Section (2,640 ) 12

13 Wattenberg Early ERL Performance Update Niobrara and Codell ERL wells are outperforming the Niobrara ERL Type Curve after 50 days Both plug-n-perf and sliding sleeve completion techniques were used in the Chestnut and Churchill pads All ERL wells TIL to date are flowing to new Aka facilities 13

14 Wattenberg Completion Enhancement Update Production enhancements NOT included in 2015 guidance or 3-year outlook Plug-n-perf Early results continue to achieve ~30-35% improvement vs. sliding sleeve Completed 16 wells in 1H additional completions planned in 2H 15 ~$100 -$200K per well AccessFrac/BioVert Early results show ~7% improvement vs. standard method Completed 17 wells in 1H additional completions planned in 2H 15 ~$50K per well 14

15 Wattenberg Midstream Update DCP Midstream System Lucerne 2 operational at the end of June Increased field-wide capacity by ~200 MMcf/d to ~850 MMcf/d Field-wide line pressure has been reduced in recent weeks Aka Energy Kersey Compressor Station operational early April Current throughput nearing capacity; overflow routed to APC facilities 34 recently completed ERL wells flow to Aka facilities 15

16 Utica Position Summary Net Acres: ~67,000 % HBP: ~50% Producing Hz Wells: 23 Potential Hz Locations: Est. Capital: $35MM 680 MBoe Condensate Window (1) Oil 50% NGL 24% Gas 26% 1,200 MBoe Wet-Gas Window (1) Oil 10% NGL 44% Gas 46% (1) Production data normalized to 5,000 lateral length. EUR volumes assume full ethane recovery. 16

17 Utica Cole and Dynamite Pad s Dynamite performance tracking ~15% above 680 MBoe type curve after 150 days Updated completion design showing significant improvements in performance Cole 4-well pad was TIL in May 2015 Currently performing ~15% above 680 MBoe type curve 17

18 Production Growth Drives Operational Efficiency 3-Year Base Case from 2015 to 2017 (1) (2) Actual 20% decrease in Operating Costs/Boe from Project 50-55% decrease in Operating Costs/Boe from Operational Resilience deliver improving cash cost structure in a lower price environment (1) Excludes ~$40.3MM in one time litigation expenses (2) Assumes mid-point of updated 2015 guidance 18

19 Strong Balance Sheet As of 6/30/15 Debt Maturity Schedule (in millions) $115 million 3.25% convertible debt matures in May 2016 $700 million revolver matures May 2018 $450 million elected commitment level $53 million drawn $12 million undrawn L.O.C. Current Borrowing Base $700 Million Elected Commitment $450 million 3.25% Convertible Notes due May 2016 Undrawn Revolver 7.75% Sr. Notes due October 2022 $500 million 7.75% senior notes mature in October 2022 $637 million available liquidity Assumes $700 million borrowing base 19

20 High-Value Crude Oil and Natural Gas Hedges Hedges in place as of June 30, 2015 July Dec ~72% of crude oil volumes at weighted average floor price of $88.99/Bbl ~72% of natural gas volumes at weighted average floor price of $3.74/MMBtu 4.1 MMBbls crude oil at weighted average floor price of $84.99/Bbl 29.8 Bcf natural gas at weighted average floor price of $3.71/MMBtu 4,140 29,750 29,510 2,847 $90.37 $3.65 $ ,508 $89.42 $96.63 $86.79 $97.55 $ ,140 $61.15 $73.77 $54.06 $3.59 $4.30 $3.92 $4.24 $3.88 $4.20 $3.65 (1) Natural gas hedged price is at NYMEX and CIG; includes Collars, Swaps and Basis Swaps 20

21 PDC Energy Differentiating Factors 2016e and 2017e are based on updated base case assumptions see slides 5 and 28 for assumptions 21

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 22

23 Appendix 23

24 2015 Financial Guidance Update In millions, except per share data Analyst Day (1) Guidance Update (2,3) Guidance Low High Production (MMBoe) Crude oil, natural gas and NGLs sales $361 - $400 $374 $394 Realized gain (loss) on derivatives Other income Adjusted total revenue $551 - $590 $600 $620 O&G production and well ops costs G&A expense Adjusted EBITDAX $387 - $414 $427 $447 Exploration expense Adjusted EBITDA $386 - $413 $426 $446 Impairment of natural gas and crude oil properties DD&A Accretion expense Net interest expense Taxes expense Adjusted net income $58 - $64 $61 $70 Adjusted cash flows from operations $355 - $380 $400 $420 Adjusted cash flows per diluted share $ $9.46 $10.05 $10.56 Adjusted net income per diluted share $ $1.60 $1.54 $1.76 (1) Pricing assumptions for the mid range of Analyst Day guidance based on NYMEX Strip of $51.72 crude oil and $2.86 natural gas. NGL price assumptions were approximately 31% of NYMEX crude oil. (2) Pricing assumptions for the mid range of guidance update based on a weighted average of 1H actuals and the July 27, 2015 NYMEX Strip, resulting in full-year of $51.21 crude oil and $2.83 natural gas. Full-year NGL prices assumes approximately 19% of NYMEX crude oil. (3) Guidance update per share based on ~39.8 million shares outstanding at year end

25 Reconciliation of Non-GAAP Financial Measures In millions, except per share data Adjusted EBITDA from net (loss): Three Months Ended June 30, Six Months Ended June 30, Net (loss) ($46.9) ($28.2) ($29.8) ($30.3) (Gain) loss on commodity derivative instruments $49.0 $53.4 ($17.6) $80.6 Net settlements on commodity derivative instruments $44.1 ($10.4) $94.5 ($18.7) Interest expense, net $10.4 $12.9 $21.0 $25.5 Income tax provision (benefit) ($30.1) ($20.5) ($19.4) ($21.9) Impairment of crude oil and natural gas properties $2.8 $0.9 $5.3 $1.9 Depreciation, depletion, and amortization $70.1 $53.7 $125.9 $100.4 Accretion of asset retirement obligations $1.6 $0.9 $3.1 $1.7 Adjusted EBITDA $101.0 $62.7 $183.0 $139.2 Weighted-average diluted shares outstanding Adjusted EBITDA per diluted share $2.52 $1.75 $4.79 $3.90 Adjusted EBITDA from net cash from operations activities: Three Months Ended June 30, Six Months Ended June 30, Net cash from operating activities $64.6 $51.1 $146.5 $131.6 Interest expense, net $10.4 $12.9 $21.0 $25.5 Stock-based compensation ($5.1) ($5.0) ($9.5) ($8.9) Amortization of debt discount and issuance costs ($1.8) ($1.7) ($3.5) ($3.4) Gain (loss) on sale of properties and equipment $0.2 $0.4 $0.2 ($0.4) Other $0.4 $1.1 $4.0 $1.7 Changes in assets and liabilities $32.3 $3.9 $24.3 ($6.9) Adjusted EBITDA $101.0 $62.7 $183.0 $139.2 Weighted-average diluted shares outstanding Adjusted EBITDA per diluted share $2.52 $1.75 $4.79 $

26 Reconciliation of Non-GAAP Financial Measures In millions, except per share data Adjusted net income (loss) from net (loss): Three Months Ended June 30, Six Months Ended June 30, Net (loss) ($46.9) ($28.2) ($29.8) ($30.3) (Gain) loss on commodity derivative instruments $49.0 $53.4 ($17.6) $80.6 Net settlements on commodity derivative instruments $44.1 ($10.4) $94.5 ($18.7) Tax effect of above adjustments ($35.4) ($16.4) ($29.2) ($23.5) Adjusted net income (loss) $10.8 ($1.5) $17.9 $8.1 Weighted-average diluted shares outstanding Adjusted net income (loss) per diluted share $0.27 ($0.04) $0.47 $0.23 Adjusted cash flows from operations from net cash from operating activities: Three Months Ended June 30, Six Months Ended June 30, Net cash from operating activities $64.6 $51.1 $146.5 $131.6 Changes in assets and liabilities $32.3 $3.9 $24.3 ($6.9) Adjusted cash flows from operations $96.9 $55.0 $170.8 $124.7 Weighted-average diluted shares outstanding Adjusted cash flows per diluted share $2.42 $1.54 $4.47 $

27 Updated Pricing Summary CRUDE OIL NGLs NATURAL GAS Wattenberg Wattenberg Wattenberg Analyst Day (FY) 2H 15 Analyst Day (FY) 2H 15 Analyst Day (FY) 2H 15 NYMEX Oil $52/Bbl $49/Bbl NYMEX Oil $52/Bbl $49/Bbl NYMEX Gas $2.85/MMBtu $2.87/MMBtu PDC Netback $42/Bbl $40/Bbl PDC Netback $15/Bbl $8/Bbl PDC Netback $2.43/Mcf $2.30/Mcf % of NYMEX 81% 80% Long term diff. ~$9/Bbl % of NYMEX 29% 16% NGL Oversupply % of NYMEX 85% 80% Utica Utica Utica Analyst Day (FY) 2H 15 NYMEX Oil $52/Bbl $49/Bbl PDC Netback $44/Bbl $42/Bbl % of NYMEX 85% 85% Analyst Day (FY) 2H 15 NYMEX Oil $52/Bbl $49/Bbl PDC Netback $23/Bbl $12/Bbl % of NYMEX 44% 25% NGL Oversupply NYMEX Gas PDC Netback % of NYMEX Analyst Day (FY) $2.85/MMBtu 2H 15 $2.87/MMBtu $2.18 /Mcf $1.75/Mcf 76% 62% TETCO M2 basis spread increase Oil currently 75% of Sales NGLs currently 7% of Sales Gas currently 18% of Sales 27

28 Wattenberg SRL Base Case Outlook Assumptions: Analyst Day vs. Current Base Case (Analyst Day) Year NYMEX Crude NYMEX Gas 2015 $51.72 $ $57.47 $ $61.24 $3.41 Rigs Wattenberg Utica Spuds / 5 rigs 0 Spuds Spuds / 6 rigs 7 Spuds / 0.5 rigs Spuds / 7rigs 14 Spuds / 1 rig Wattenberg - 14 and 16 day spud to spud Wattenberg - $3.4MM (SRL) and $4.4MM (ERL) well costs Utica rig deployed in 2H 16 + FY2017 Commodity pricing as of 03/20/15 Efficiencies/Cost Reductions Updated Base Case Year NYMEX Crude NYMEX Gas 2015 $51.13 $ $52.49 $ $56.38 $3.31 Rigs Wattenberg Utica 2015 ~155 Spuds / 5 rigs 0 Spuds 2016 ~140 Spuds / 4 rigs 3 Spuds Spuds / 4-5 rigs 0 Spuds Wattenberg - 10 and 12 day spud to spud Wattenberg - $3.1MM (SRL) and $4.1MM (ERL) well costs Utica rig deployed for 3 wells in 2016 Commodity pricing as of 07/27/15 Spud to TD: TD to Rig Release: Rig Move: Current Outlook 2015 Analyst Day Days 28

29 Niobrara Gas-Oil Ratio (GOR) Discussion Niobrara GOR variation in Wattenberg critical for accurate forecasting Varying Liquids Content Across Core Areas Range of Area Type Curve Inner Middle Outer Producing GOR Stable After 1-2 Years Low Niobrara GOR High 29

30 Codell GOR Variation in Wattenberg Codell GOR variation in Wattenberg critical for accurate forecasting Varying Liquids Content Across Core Areas Range of Area Type Curve Inner/Middle Outer Producing GOR Stabilizes After 1 2 Years Low Codell GOR High 30