CAPITAL ONE SECURITIES 10 th ANNUAL ENERGY CONFERENCE
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 and that we expect to meet or exceed the high end of our range; 2016 capital budget and production forecasts, including anticipated liquidity and year-end 2016 debt to EBITDA; expected 2016 capital forecast allocations; anticipated commodity mix in 2016; anticipated cash flow and spend rates, targeting cash flow neutrality; the impact of prolonged depressed commodity prices; the Utica Shale impairment and other potential future impairments; availability of sufficient funding for the remainder of our 2015 and our 2016 capital program and sources of that funding; future exploration, drilling and development activities, including our expected rig count, wells spud and turn-in-lines in both the Utica Shale and Wattenberg Field; expectation of cash flows in 2015 and 2016; potential additional revisions to our 2016 capital and production forecast; anticipated reductions in our 2016 cost structure; the expiration of certain leases and our current development plan in the Utica Shale; our evaluation method of our customers' and derivative counterparties' credit risk, including certain of our gas marketing customers; our expected positive net settlements on our derivative positions and effect on cash flow in 2015; effectiveness of our derivative program in providing a degree of price stability; the timing, availability, cost and effect of additional midstream facilities and services going forward; expected differentials; compliance with debt covenants; expected funding sources for anticipated net settlement 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, the Company uses the terms outlook, projection or similar terms or expressions, to indicate that it has modeled certain future scenarios. PDC typically uses these terms to indicate its current thoughts on possible outcomes relating to its 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 the Company views as the most likely to occur, but instead are shown to illustrate aspects of its business in the context of a variety of scenarios it believes 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. 2015 PDC Energy, Inc. All Rights Reserved. December 8, 2015 2
PDC Energy High Quality Assets Company Highlights Core Wattenberg Market Cap: ~$2.2 Billion (1) Enterprise Value: ~$2.8 Billion (1) YE 2014 proved reserves 250 MMBoe 64% liquids, 30% proved developed Capital expenditure guidance 2015: ~$535 MM 2016: $450 - $500 MM Production guidance 2015: expect to meet or exceed 15.0 MMBoe ( 41,100 Boe/d) 2016: 20.0 to 22.0 MMBoe (54,650 60,100 Boe/d) (1) As of December 3, 2015; Approximately 40 million shares outstanding Utica 3
PDC Energy Strong Results, Great Positioning Third quarter highlights ~47,000 Boe/d production (84% growth y/y, 27% q/q) Adj. cash flow from operations of $123 million (exceeds capex of $104 million) LOE of $2.87/Boe (37% decrease from 3Q 2014) 10% improvement in drill times from 2Q 2015 Strong Balance Sheet Liquidity of ~$642 million (as of 9/30/15) Strong unhedged margins Solid 2016 and 2017 hedge portfolio Full-year 2015 expectations Meet or slightly exceed top end of guidance (15 MMBoe) Capital expenditures within guidance of $520 - $550 million LOE trending to low-end of guidance ($3.70 - $3.90/Boe) Cash flow neutral in 4Q 2015 Reduced rig count from five to four in November 4
Days MMBoe PDC Energy 2016 Production Guidance Highlights Annual production of 20.0 22.0 MMBoe 54,650 60,100 Boe/d 35-40% growth over 2015e Annual Production (3) 20.0-22.0 Four rig program in Wattenberg ~25% increase in lateral foot drilled per rig-year ~160 TILs (1) and 135 spuds in Wattenberg 6.5 9.3 >15.0 Plug-n-perf ( PnP ), AccessFrac, downspacing evaluation and mono-bore drilling in 2016 2016 Wattenberg Drilling Details (2) All numbers approximate SRL ERL XRL Lateral length 4,200 6,900 9,500 Drilling days (spud-to-spud) 7 11 14 Portion of spuds 32% 36% 32% Portion of TILs 50% 40% 10% Completed well cost (MM) w/pnp $2.9 $3.9 $5.0 16 12 8 4 0 2013 2014 2015e 2016e Wattenberg SRL Drilling 7 days spud-tospud 2014 2015 AD 2015 3Q 2016e Spud to TD TD to Rig Release Rig Move (1) TIL = turn-in-line; (2) SRL = standard reach lateral, ERL = mid-length lateral, XRL = extended reach lateral; (3) From continuing operations 5
millions PDC Energy 2016 Capital Budget Highlights Plan to spend ~$450 - $500 million ~11% reduction from 2015 $800 Capital Expenditures Anticipated YE Debt to EBITDA of ~1.4x $600 $637 $450-$500 Mark-to-market value of future hedges exceeds $250 million (as of 11/30/15) $400 $200 ~$535 Targeting cash flow neutrality Weighted average NYMEX 2016 prices: $53/Bbl; $2.60/Mcf; NGL realizations 18% NYMEX oil $0 2014 2015e 2016e Drill, complete and TIL five Utica wells 2.5x Debt to EBITDA Oil Price Sensitivity Oil price (NYMEX) 1 $40 $45 $53 2.0x 1.5x 1.9x 1.5x 1.4x Outspend (millions) $70 $47 $10 Year-end debt to EBITDA 1.7x 1.6x 1.4x Year-end liquidity (MM) $442 $460 $500 1.0x 0.5x 0.0x 2014 2015e 2016e (1) Assumes 4 rig program throughout 2016, gas and NGL prices of $2.60/Mcf and 18% NYMEX 6
PDC Energy Delivering Value Through Execution VALUE DRIVER 2015 Guidance 2016 Guidance PRODUCTION GROWTH ~60% ~35-40% DRILLING EFFICIENCIES 14+ days SRL spud-to-spud 7 day SRLs spud-to-spud HIGH-RETURN PROJECTS ~30-60% IRRs on 2015 drilling at $50 oil Extensive inventory of high IRR projects FINANCIAL STRENGTH 2015 YE Debt:EBITDA of ~1.5x EXECUTION 2016 YE Debt:EBITDA 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 7
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 (YE 2014) Based on ~16 Niobrara &~4 Codell per section 2016 drilling program: 4 ADR (1) rigs XRLs of ~9,500 to be drilled Plug-n-Perf completions the new standard AccessFrac to be tested with Plug-n-Perf Mono-bore drilling Evaluate 22- and 26-well per section equivalent projects drilled in 2015 (1) Automated Drilling Rigs 8
Wattenberg Extensive Drilling Inventory Year-end 2014 locations 2P SRL Location IRRs (1) ~2,640 Locations 600 135 375 1,500 Locations 2016 Drilling Program 40-60% 30-40% 20-30% 15-20% 2015 2016 2017 2018 2019 2020 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
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
Wattenberg Technical Development Progress Current Drilling Rig Location; All projects drilled on 16 wells per section equivalent unless otherwise noted Key Technical Updates: 47 Extended Reach Lateral Wells Currently Producing: Chesnut (Sec. 28): 10 wells Middle Core 20 well-equivalent 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 Bernhardt Farms: 5 wells Middle Core Wells were TIL in mid/late August Stroh: 8 wells Middle Core Wells were TIL late September Downspacing Projects: Becker Ranch: 19 wells Middle Core (22 well-equivalent) Wells were TIL in November Rieder: 13 wells Middle Core (26 well-equivalent) Wells were TIL late October 11
Wattenberg 2015 Downspacing Projects 22 Wells/Section 20 Wells/Section Chesnut (2Q15 TIL) 480-acre unit ERL downspacing test 6,700 laterals 10 wells 5 NIO (64-acre spacing) 5 CDL (64-acre spacing) Becker Ranch (4Q15 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 (4Q15 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
Gross 2-Phase Daily Production (Boe/d) Wattenberg Early Chesnut Downspacing Results 1,000 Early Downspacing Results - Chesnut (Sec. 28) Pad 100 10 Avg. Niobrara ERL Avg. Codell ERL Niobrara ERL Type Curve - 600 Mboe 1 31 61 91 121 151 Days on Production 10 wells on a 20 well-equivalent spacing All wells are also extended reach laterals (6,500 lateral) Early results are very encouraging, but the continued monitoring of performance is crucial 13
Gross 2-Phase Daily Production per 1,000' of Lateral (Boe/d) Wattenberg Plug-n-Perf Performance Update 1,000 Dataset includes: 8 Standard length PnP wells 8 Standard length Sliding Sleeve wells 100 10 440 Mboe Middle Core Niobrara Type Curve Avg. Sliding Sleeve Completion Avg. Plug-n-Perf Completion 1 31 61 91 121 151 181 211 241 271 301 331 361 Days on Production Strong improvement to production from plug-n-perf completion technique TIL 31 plug-n-perf wells through nine months of 2015 - Expect majority of 2016 program to have plug-n-perf completions 14
Wattenberg Midstream Update DCP Lucerne 2 Operational at the end of June Field-wide average pipeline pressures significantly lower compared to 2014 and 1H15 Increased field-wide capacity by 200 MMcf/d to ~850 MMcf/d Current system throughput ~730-750MMcf/d Excess capacity of ~100 MMcf/d Aka Kersey Station Operational early April Current throughput nearing capacity 34 ERL wells TIL to Aka facilities 15
Utica Position Summary Net Acres: ~67,000 % HBP: ~50% Producing Hz Wells: 23 Potential Hz Locations: 220 2016 Est. Capital: $34MM 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
Utica Update Dynamite and Cole Pad Performance Dynamite and Cole 4-well pads both performing above 680 MBoe type curve after 150 days Updated completion design showing significant improvements in performance 17
Utica Gas Gathering Summary Two Primary Long-Term Processing Contracts MarkWest (MWE) PDC volumes flow to Seneca Plant Access to all major NGL takeaway projects in the northeast region MWE has current capacity of 1.3 Bcf/d with planned expansion to 1.5+ Bcf/d in 2016 Blue Racer (BRM) PDC volumes flow to both Berne and Natrium plants BRM has current capacity of 800 MMcf/d Access to NGL markets via rail, truck, pipeline, or barge 18
Production Growth Drives Operational Efficiency (1) (2) Actual 20% decrease in Operating Costs/Boe from 2012-2014 Project 50-55% decrease in Operating Costs/Boe from 2012-2017 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 19
Debt and Liquidity As of 9/30/15 $115 million 3.25% convertible debt matures in May 2016 Fall redetermination: $700 million revolver reaffirmed and maturity extended two years to May 2020 $450 million elected commitment level $50 million drawn $12 million undrawn L.O.C $500 million 7.75% senior notes mature in October 2022 $1,000 $800 $600 $400 Debt Maturity Schedule (in millions) Current Borrowing Base $700 Million Elected Commitment $450 million 3.25% Convertible Notes due May 2016 Undrawn Revolver Drawn @9/30/2015 7.75% Sr. Notes due October 2022 $700 $500 $642 million available liquidity Assumes $700 million borrowing base $200 $115 Debt/LTM EBITDAX (1) of ~ 1.6x $- $50 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 (1) LTM EBITDAX is last twelve months adjusted EBITDA plus exploration expense, excludes gain/loss on sale of assets 20
Crude Oil and Natural Gas Hedges Summary Hedges in place as of September 30, 2015 plus hedges entered into prior to October 30, 2015 Oct Dec 2015 2016 ~69% of crude oil volumes at weighted average floor price of $88.99/Bbl ~70% of natural gas volumes at weighted average floor price of $3.74/Mcf 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 $3.67/Mcf (1) 4,140 29,750 31,010 $90.37 $3.58 $3.53 1,421 1,440 $89.42 $96.63 $86.79 $97.55 $77.59 $56.99 $73.77 $54.06 6,356 $3.59 $4.30 $3.92 $4.24 $3.88 $4.13 $3.59 (1) Natural gas hedged price is at NYMEX and CIG; includes Collars, Swaps and Basis Swaps 21
PDC Energy Differentiating Factors Peer-leading production growth Anticipated 35-40% growth in 2016 Substantial YE14 2P Inventory ~2,640 high rate-of-return locations in Core Wattenberg Strong Balance Sheet Projected YE16 Debt to EBITDAX of approximately 1.4x Significant hedge portfolio ~50% of 2016 oil volumes at ~$85/Bbl ~63% of 2016 natural gas volumes at $3.63/Mcf 22
Investor Relations Mike Edwards, Senior Director Investor Relations michael.edwards@pdce.com Kyle Sourk, Manager Investor Relations kyle.sourk@pdce.com Corporate Headquarters PDC Energy, Inc. 1775 Sherman Street Suite 3000 Denver, Colorado 80203 303-860-5800 Website www.pdce.com 23
Appendix 24
2015 Financial Guidance Update In millions, except per share data Analyst Day (1) Guidance Update (2,3) Guidance Low High Production (MMBoe) 13.5-14.5 14.7 15.0 Crude oil, natural gas and NGLs sales $361 - $400 $374 $394 Realized gain (loss) on derivatives 188 224 224 Other income 2 2 2 Adjusted total revenue $551 - $590 $600 $620 O&G production and well ops costs 89 95 95 93 G&A expense 75 81 78 80 Adjusted EBITDAX $387 - $414 $427 $447 Exploration expense 1 1 1 Adjusted EBITDA $386 - $413 $426 $446 Impairment of natural gas and crude oil properties 9 8 13 11 DD&A 229 250 265 275 Accretion expense 7 6 7 7 Net interest expense 48 46 42 41 Taxes expense 35 39 38 42 Adjusted net income $58 - $64 $61 $70 Adjusted cash flows from operations $355 - $380 $400 $420 Adjusted cash flows per diluted share $8.84 - $9.46 $10.05 $10.56 Adjusted net income per diluted share $1.44 - $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 2015 25
Updated Pricing Summary OIL NGL NATURAL GAS Wattenberg 2016 Wattenberg 2016 Wattenberg 2016 NYMEX Oil $53/Bbl NYMEX Oil $53/Bbl NYMEX Gas $2.60/MMBtu PDC Netback $48/Bbl PDC Netback $9/Bbl PDC Netback $2.00/Mcf % of NYMEX 87% Long term diff. ~$9/Bbl % of NYMEX 18% NGL Oversupply % of NYMEX 77% Utica Utica Utica 2016 2016 2016 NYMEX Oil $53/Bbl PDC Netback $47/Bbl % of NYMEX 86% NYMEX Oil $53/Bbl PDC Netback $11/Bbl % of NYMEX 20% NGL Oversupply NYMEX Gas PDC Netback % of NYMEX $2.60/MMBtu $1.92/Mcf 74% TETCO M2 basis spread increase 26
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 27
Reconciliation of Non-GAAP Financial Measures In millions, except per share data Adjusted EBITDA from net income (loss): Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Net income (loss) ($41.5) $54.0 ($71.3) $23.7 (Gain) loss on commodity derivative instruments ($123.5) ($92.2) ($141.2) ($11.6) Net settlements on commodity derivative instruments $68.0 ($4.1) $162.5 ($22.7) Interest expense, net $10.7 $12.4 $31.8 $37.9 Income tax provision (benefit) ($21.2) $38.5 ($40.6) $16.6 Impairment of crude oil and natural gas properties $153.5 $2.2 $158.8 $4.0 Depreciation, depletion, and amortization $81.0 $50.9 $206.9 $151.3 Accretion of asset retirement obligations $1.6 $0.9 $4.7 $2.6 Adjusted EBITDA $128.6 $62.6 $311.6 $201.8 Weighted-average diluted shares outstanding 40.1 36.8 38.8 36.8 Adjusted EBITDA per diluted share $3.21 $1.70 $8.03 $5.48 Adjusted EBITDA from net cash from operations activities: Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Net cash from operating activities $136.5 $70.4 $283.0 $202.0 Interest expense, net $10.7 $12.4 $31.8 $37.9 Stock-based compensation ($4.8) ($4.2) ($14.3) ($13.1) Amortization of debt discount and issuance costs ($1.8) ($1.8) ($5.3) ($5.2) Gain (loss) on sale of properties and equipment $0.1 - $0.3 ($0.4) Other $1.7 $0.7 $5.5 $2.4 Changes in assets and liabilities ($13.8) ($14.9) $10.6 ($21.8) Adjusted EBITDA $128.6 $62.6 $311.6 $201.8 Weighted-average diluted shares outstanding 40.1 36.8 38.8 36.8 Adjusted EBITDA per diluted share $3.21 $1.70 $8.03 $5.48 28
Reconciliation of Non-GAAP Financial Measures In millions, except per share data Adjusted net income (loss) from net income (loss): Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Net income (loss) ($41.5) $54.0 ($71.3) $23.7 (Gain) loss on commodity derivative instruments ($123.5) ($92.2) ($141.2) ($11.6) Net settlements on commodity derivative instruments $68.0 ($4.1) $162.5 ($22.7) Tax effect of above adjustments $21.1 $36.6 ($8.1) $13.0 Adjusted net income (loss) ($75.9) ($5.7) ($58.1) $2.4 Weighted-average diluted shares outstanding 40.1 36.8 38.8 36.8 Adjusted net income (loss) per diluted share ($1.89) ($0.15) ($1.50) $0.07 Adjusted cash flows from operations from net cash from operating activities: Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Net cash from operating activities $136.5 $70.4 $283.0 $202.0 Changes in assets and liabilities ($13.8) ($14.9) $10.6 ($21.8) Adjusted cash flows from operations $122.7 $55.5 $293.6 $180.2 Weighted-average diluted shares outstanding 40.1 36.8 38.8 36.8 Adjusted cash flows per diluted share $3.06 $1.51 $7.57 $4.90 29