MIZUHO SECURITIES. January 24, 2014 NASDAQ:PDCE

Transcription

1 MIZUHO SECURITIES January 24, 2014 NASDAQ:PDCE

2 Forward Looking Statements This presentation, including verbal statements made in connection herewith, 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 Energy, Inc. s ( PDC or the Company ) business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this presentation are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of Words such as expects, anticipates, intends, plans, believes, seeks, estimates, forecasts, guidance, outlook, and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements may relate to, among other things: estimated natural gas, natural gas liquids ( NGLs ) and crude oil reserves; future production (including the components of such production and production from particular wells or projects), expenses, cash flows, margins, rates of return, liquidity, prices, debt levels, earnings, EBITDAX, EBITDA and reserves; anticipated capital projects, expenditures and opportunities, including drilling locations and downspacing potential; Utica development potential; future exploration and development activities; the Company s 2014 guidance; expected capital allocation; expected commodity mix; availability of additional midstream facilities; expected timing of the 5 th rig in the Wattenberg, particularly in the Wattenberg and in the Utica, and the timing of that availability; the impact of third-party midstream capacity constraints; availability of sufficient funding for PDC s capital program and sources of that funding; PDCM s capital budget funding; the future effect of contracts, policies and procedures PDC believes to be customary; effectiveness of the Company s derivative program in providing a degree of price stability; and the Company s future strategies, plans and objectives. The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this presentation reflect PDC s good faith judgment, such statements can only be based on facts and factors currently known to the Company. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Estimates of non-proved reserves are subject to significantly greater risk of not being produced than proved reserves. Initial and test results from a well are not necessarily indicative of the well s long-term performance. 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, 2012 and PDC s other filings with the U.S. Securities and Exchange Commission ("SEC"), all of which are incorporated by reference herein, for further information on risks and uncertainties that could affect the Company s business, financial condition, results of operations and cash flows. PDC cautions you not to place undue reliance on forward-looking statements, which speak only as of the date of this presentation. 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. 2

3 Company Overview NASDAQ: PDCE Market cap ~$1.8 Billion (1) Enterprise value ~$2.4 Billion (1) Strategic Core Areas Colorado and Appalachian Basin Proved reserves (YE2012) 179 MMBoe (2) WATTENBERG UTICA 52% liquids, 38% proved developed 3P reserves (YE2012) 589 MMBoe (2) Significant inventory of lower risk horizontal development projects Wattenberg Field - Colorado Utica Shale - Ohio 2013E: 15,039 Boe/d ~98,000 Net Acres (2) ~95% HBP 2,000 HZ Projects 50% - 140% IRR (3) 70-80% Liquid Mix Liquid- Rich Basins 2013E: 1,074 Boe/d ~48,000 Net Acres 57% HBP 200 HZ Projects (1,000 spacing) 30% - 80% IRR (3) 50-80% Liquid Mix Marcellus Shale West Virginia 2013 Net production guidance of 7.0 to 7.5 MMBoe comprised of 54% liquids (2) (mid-point ~7.3 MMBoe or 20,000 Boe/d) 2014 Net production guidance of 9.5 to 10 MMBoe comprised of ~60% liquids (range 26,000 to 27,400 Boe/d) Closed sale of non-core Colorado dry gas assets mid-june with net proceeds of ~$178 million Closed Equity Offering August 9 th net proceeds of ~$276 million for ~5.2 million shares PDC ENERGY TOTAL 2013E: 19,898 Boe/d ~270,000 Net Acres (2) ~90% HBP 2,800 HZ Projects MARCELLUS APPALACHIAN BASIN 2013E: 22,708 Mcfe/d (3,785 Boe/d) 125,250 Net Acres 97% HBP 600 HZ Projects ~25% IRR (3) (1) Company estimate as of 1/22/2014. Approximately 35.6 million shares outstanding. (2) From continuing operations, pro forma for Colorado divestiture. (3) Flat Pricing: $90 NYMEX Oil, $4.00 NYMEX Gas. Excludes lease acquisition and corporate-level costs. 3

4 YE2012 Reserves Summary Significant 3P Reserves Growth (MMBoe) Proved Reserves 52% liquids; 62% PUDs; PV-10 of ~$1.7 billion Development of Wattenberg expected to add significant 3P reserves to PDC s portfolio Continued delineation of horizontal Codell and promising initial results of downspacing in Niobrara Utica has the potential to significantly increase PDC s 3P reserves in 2013 and beyond Current development plan expected to accelerate movement of reserves towards 1P status Area of Continuing Operations PD PUD Total Proved (1P) Probable & Possible (1) 3P Wattenberg Utica WV Appalachia (net to PDCE) Total PDC Energy (1) Probable and Possible reserves are non-sec internal estimates run at year-end 2012 SEC pricing of $94.71 oil, $2.76 natural gas and $37.29 NGLs; All reserves reflect sale of non-core Colorado natural gas assets. (2) YE2011 1P reserves were 99 MMBoe; YE2011 3P reserves were 249 MMBoe. 80% Increase from YE2011 (2) 236% Increase from YE2011 (2) 4

5 2014 Capital Budget Wattenberg Utica PDCM 50% Other 72% Area Capital Budget ($MM) Operated Horizontal Rigs Operated Horizontal New Drills 25% Wattenberg $467 (1) % 2% 97% of Capex allocated to liquids-rich projects 89% of Capex allocated to development projects PDCM s (50/50 Joint Venture) capital budget is expected to be funded by the JV s cash flow and borrowings under the JV s revolving credit facility Utica $ Other $2 - - Sub-Total $ Marcellus Shale (PDCM 50%) $ Total $ Wattenberg horizontals: 59 Codell, 56 Niobrara; 20 with laterals of 6,500 6,700 Development Projects Focused on Low-Risk Liquid-Rich Areas (1) Includes $100 million for non-operated projects including ~$50 million for PDC share of 26-well per section test. 5

6 Production by Area Area (Boe/d) E 2014E Q1 '13 Q2 '13 Q3 '13 Wattenberg 12,180 15,038-15,389 15,019 14,590 Utica - 1, Marcellus / Other 2,820 3,784-2,922 2,852 3,684 Continuing Ops (1) 15,000 19,896 26,700 18,500 18,089 18, Quarterly Net Production (Boe/d) 30,000 Oil / Liquids Gas 25,000 20,000 15,000 10,000 5,000 0 Plan Actual Plan Actual Plan Actual Plan Actual (1) Non-core Colorado asset divestiture closed June 18, E and 2014E are mid-points of guidance range. Gas 65% 2012 Commodity Mix (1) Oil 25% NGL 10% Gas 40% 2014E (1) NGL 15% 4Q Production Catalysts Wattenberg: 16 wells at Waste Management Section ~15 additional completions in Nov. & Dec. DCP Gas Plant online early October Oil 45% 35% Liquids 60% Liquids Production up ~12% from 2,300 legacy wells DCP system throughput >500 MMcfd Utica: Stiers 3-wells tied into MarkWest mid-november 2 new Detweiler & 2 new Commissioners wells Gavin 1H produced while drilling offsets (2H & 3H) Marcellus: OES 3-well pad online late November 6

7 Core Horizontal Wattenberg ~98,000 net acres, 95% HBP Third largest leaseholder and producer 70% - 80% liquids Niobrara Wt. Avg. Inventory EUR of 335 Mboe per well Excellent returns IRR of 50% - 140% (1) 2,000 gross horizontal locations Additional downspacing opportunities exist Niobrara downspacing Horizontal Codell Strong repeatable lower risk results (1) Flat pricing: $90 NYMEX oil, $4.00 NYMEX gas. 7

8 DJ Basin Stratigraphic Column Multiple Target Zones Current PDC Operations ~2,300 net producing vertical wells ~113 producing horizontal wells (1) Fourth drilling rig added in Dec. 13, 5 th rig ~May 14 Spud 119 gross wells (70 operated, 49 non-operated) horizontal wells in 2013 in the Wattenberg field Drill using 3 to 8 well pads Currently drilling 16-wells per section Niobrara (A,B,C) and Codell Formations all productive 7,300 average depth to base of Niobrara 300 to 350 thickness of Niobrara/Codell package 4,000 6,000 lateral length Drill time of days spud-to-spud Sliding sleeves, swell / HYD packers frac stages per well / completed in ~24-hour Average $4.2MM D&C cost / well (1) As of 12/31/13. 8

9 Wattenberg Project Inventory YE2012 (1) Proved HZ Inventory (2) 4 Gross HZ wells (Niobrara only) per 640 Ac. Gross HZ Inventory: 382 2P HZ Inventory (2) 10 Gross wells per 640 Ac. (8 Niobrara, 2 Codell) Gross HZ Inventory: ~1,400 3P HZ Inventory (2) 16 Gross wells per 640 Ac. (12 Niobrara, 4 Codell) Gross HZ Inventory: ~2,000 (1) Vertical wells may or may not be present. (2) Reserves Waste Management Section 9

10 Horizontal Niobrara Performance Inner Core Middle Core Outer Core Average EUR 1 Range of Industry Results Average EUR 1 Range of Industry Results Average EUR 1 Range of Industry Results 900 MBoe 300 MBoe 600 MBoe 200 MBoe 500 MBoe 150 MBoe Average Economics Average Economics Average Economics Average 3-Phase EUR: 500 MBoe Average 3-Phase EUR: 365 MBoe Average 3-Phase EUR: 265 MBoe PDC 3P Inventory: 93 wells PDC 3P Inventory: 957 wells PDC 3P Inventory: 537 wells Well Capex: $4.2MM Well Capex: $4.2MM Well Capex: $4.2MM % Liquids: 56% IRR 2 : 140% % Liquids: 69% IRR 2 : 81% % Liquids: 77% IRR 2 : 50% PV10: $7.0MM PV10: $4.5MM PV10: $3.2MM (1) Type curves based on actual production data from ~450 wells drilled by PDC and industry through early (2) Flat Pricing: $90 NYMEX Oil, $4.00 NYMEX Gas. Excludes lease acquisition and corporate-level costs. 10

11 Horizontal Codell Development Strong Well Performance Shows Potential for Development Across Wattenberg Large exposure with nearly all acreage having horizontal Codell potential Codell horizontals showing results similar to horizontal Niobrara wells Only 5 horizontals booked as PUDs at YE2012 Codell horizontals planned: 35 for 2013; 59 in 2014 Initial results show little depletion or interference from existing vertical Codell wells Gathering new data for YE2013 proved reserve additions (1) Waste Management Section HZ Codell Inventory YE2012 Proved (1P) Proved + Probable + Possible (3P) (2) (1) PDC Codell locations may contain multiple wells. (2) Probable and Possible reserves are non-sec internal estimates. Gross Well Inventory Net Reserves (MMBoe)

12 Horizontal Codell Performance Avg. 3-phase EUR: 345 MBoe Current Type Curve Avg. 3-Phase EUR: 345 MBoe PDC 3P Inventory: 455 wells Capex: $4.2MM % Liquids: 75% IRR 1 : 77% PV10: $5.2MM (1) Flat Pricing: $90 NYMEX Oil, $4.00 NYMEX Gas. Excludes lease acquisition and corporate-level costs. 12

13 West East Side View Waste Management 16-Well Section Fall N-64W-2 All 16 wells as Hz Codell Economics Average 3-Phase EUR: 345 MBoe % Liquids: 75% IRR: 77% PV10: $5.2MM Middle Core Economics Average 3-Phase EUR: 365 MBoe % Liquids: 69% IRR: 81% PV10: $4.5MM Outer Core Economics Average 3-Phase EUR: 265 MBoe % Liquids: 77% IRR: 50% PV10: $3.2MM (1) Flat Pricing: $90 NYMEX Oil, $4.00 NYMEX Gas. Excludes lease acquisition and corporate-level costs Producing Producing Producing Nov. 12 th 6 Codell wells 10 Niobrara wells 6 B bench 4 C bench All 16 wells drilled by early October Westerly 8 wells on line early Oct.; Remaining 8-wells on line as of November 12 th 4,950 13

14 3 rd Party Midstream Expansion - Wattenberg One Bcfe per Day of Capacity Planned PDC Acreage 2013 Compressor Site 2014 Compressor Site Processing Plant 2013 in service Lucerne 2 Plant Sullivan CS Wells Ranch CS Plants and compression strategically placed around PDC acreage O Connor* plant (160 MMcf/d) started-up October 10 th By-pass projects Q3 13 increased system capacity Lucerne 2 plant (230 MMcf/d) expected start-up early 2015 Plant 10 (230 MMcf/d) planned in 2016 PDC expects to have ample capacity to expand drilling program in Troudt CS Libsack CS 70 Ranch CS Wattenberg Greatest benefit to line-pressure is on outer edges (low GOR) FREX to provide Mont-Belvieu NGL market (2014) Bernhardt CS O Connor* Plant Godfrey Bottoms CS Tampa CS PDC legacy vertical production up approx. 12% due to O Connor* Plant FREX NGL Line * DCP renamed the LaSalle Plant in honor of its retiring Chairman O Connor. 14

15 Utica Leasehold and Activity - drilled and/or completed - planned 2014 spud 11 - Wells to sales by YE 2013 Stiers 3-Well Hz Pad, 5,000 laterals, 67 total stages Palmer #44-20 Vertical test well Oil Wet Gas Condensate Dry Gas 1 Onega-Comm #14-25H 3,950 lateral, 13 stages Commissioners #2H & #3H 4,300 laterals, 22 & 21 stages (to sales in December) Palmer #1H, #2H& #3H Currently drilling Neill #1H 6,000 lateral, 33 stages 10 & 11 7 Detweiler #42-3H 2 3,900 lateral, 13 stages Detweiler #2H & #3H 8 9 4,300 laterals, 22 stages each (#2H & 3H to sales late Nov.) Garvin #1H 4,800 lateral, 22 stages Completing: Garvin #2H 4,800 lateral Garvin #3H 6,800 lateral 6 ~48,000 net acres, 57% HBP, 95% WI, 16% royalty ~200 gross horizontal locations (1,000 ft. spacing) ~25% acreage in Guernsey & N. Noble Counties ~75% acreage in Washington, S. Noble, Morgan Counties Currently drilling 14 th Hz well (1 st in 2014) 1st well on 3-well Palmer Pad Midstream services MarkWest Northern acreage, in service Blue Racer Southern acreage 11 wells to sales by YE 2013 with exit rate of ~5,200 Boe/d Garvin 1H produced while #2H & #3H drilled; Neill 1H remains on flowback Stiers 3-well pad to sales mid-november new Detweiler & 2 new Commissioners wells to sales November/December (1) Rates are 3-stream estimates. 15

16 Gross 3-Phase Daily Production (Boed) Casing Pressure (psi) Garvin 1-H Initial Performance Very encouraging initial performance from Southern Utica acreage test Little drawdown in reservoir pressure during variations of choke sizes Signals higher than expected fracture conductivity Managing flowback techniques becoming critical to maximizing long-term productivity of Utica wells` 6,000 5,000 4,000 Garvin 1-H 24-Hr IP Flowrate vs Choke Size Garvin 1-H Performance Garvin 1-H Flowing Csg Pressure OBSERVED FORECASTED 6,000 5,000 4,000 3,000 3,000 2,000 2,000 1,000 1, Choke Size (64th in.) 0 16

17 Utica Drilling & Completions Multi-well pads Testing different reservoir landing zones Targeting 5,000 to 6,000 ft. laterals 1,000 ft. spacing between wells Evaluating different completion designs Using 20 to 30 frac stages per well Slight variation of fluid and proppant volumes Testing different proppant types Varying flowback methods Utilizing micro-seismic 17

18 Appalachian Basin - Marcellus PDCM Marcellus Acreage 3 producing O.E.S 3-well pad 125,250 (1) Marcellus net acres to PDCM 54 Marcellus productive wells (39 Horizontal) 1 D Annunzio 4-well pad producing 4 Armstrong/Reynolds 4-well pad 357 of 600 undeveloped horizontal Marcellus locations in 3-county focus area of West Virginia D Annunzio 4-well pad online early August; Goff 3-well pad to sales in August OES 3-well pad to sales late November 2 Goff 3-well pad producing All wells drilled on Armstrong/ Reynolds 4-well pad completions and to sales in March (1) Comprised of 116,250 net acres in WV and 9,000 net acres in PA. The 600 horizontal locations are on WV acreage only. 18

19 Debt Maturity Schedule $ in Millions $115 million 3.25% convertible debentures mature in May 2016 Debt Maturity Schedule $40 million PDCM revolver matures in April 2017; $15 million second lien matures in October 2017 (1) $450 million revolver matures in May % Convertible Notes due PDCM $450 Undrawn Revolver - PDC 7.75% Notes due 2022 $500 $500 million 7.75% senior notes mature in October As of September 30, 2013 (2) $0 drawn on bank credit facility $18 million undrawn L.O.C $298 million cash balance $730 million available liquidity $115 $55 $50 $ Maturity schedule reflects: Mitigation of liquidity risk Diversification of funding sources (1) Includes additional $30 million of borrowing outstanding on PDCM second lien, of which $15 million is net to PDC. (2) Excludes PDCM. 19

20 Crude Oil and Natural Gas Hedges Hedges in Place as of December 31, 2013 Crude Oil (includes NGL) FY2014 FY2015 FY2016 NYMEX Average (1) $96.36 $88.75 $83.83 Weighted-Average Hedge Price With Ceilings $94.15 $89.35 N/A Weighted-Average Hedge Price With Floors $89.03 $88.10 N/A Hedge Volumes (MBBL) 4,112 4,501 - Natural Gas FY2014 FY2015 FY2016 NYMEX Average (1) $4.19 $4.14 $4.13 Weighted-Average Hedge Price With Ceilings (2) $4.03 $4.16 $4.13 Weighted-Average Hedge Price With Floors (3) $4.03 $4.03 $4.00 Hedge Volumes (MMcf) 20,156 20,820 16,740 (1) As of 12/31/2013 Strip Price. (2) Hedge price is at NYMEX, and CIG. (3) Hedge price is at NYMEX, and CIG; Includes Swaps, Basis Swaps and Floors. 20

21 2013 Investment Utica Objectives Highlights Positioned to execute multi-year organic growth of production, cash flow and proved reserves Significant horizontal projects in inventory Core Wattenberg Niobrara and Codell / Colorado Utica Shale / Southeast Ohio Marcellus Shale / West Virginia Significant operating expertise in focus areas Strong liquidity and solid balance sheet Proactive hedging strategy helps protect cash flow Focused on improving cash margins through low-cost operations and midstream / marketing initiatives Capital primarily allocated to projects that increase liquids-mix in production and proved reserves Operational flexibility; largely HBP and operated 21

22 Investor Relations Mike Edwards, Senior Director Investor Relations Marti Dowling, Manager Investor Relations Corporate Headquarters PDC Energy, Inc Sherman Street Suite 3000 Denver, Colorado Website 22

23 APPENDIX 23

24 Average Rock Properties PDC Acreage Utica Geologic Summary Utica Palmer Onega Commissioners Hickenbottom A A Morgan County Guernsey County Belmont County Pt. Pleasant Trenton Resistivity (ohm-m) 800 2,000 1,000 2,000+ 1,000 2,000+ Porosity (%) 6-11% 6-12% 6-13% Thickness of Pt. Pleasant (ft) Total Organic Content (TOC) Max 4.4 Max 4.8 (est.) Max 4.5 Formation Depth (ft) 6,750 6,850 7,135 7,247 9,188 9,305 BTU of gas stream 1,261 1,254 1,040 24

25 PDCE Share Count Leverage to Top-Tier Plays PDCE Highly Leveraged To the Top Liquids-Rich US Onshore Basins 2,000 1,500 1, ,000 3,000 2,000 1,000 0 Utica: Net Acreage/Million Outstanding Shares 1,654 Gulfport 3,271 PDC Energy 1,506 PDC Energy 2,291 Noble HESS Anadarko Magnum Hunter Core Wattenberg: Net Acreage/Million Outstanding Shares Bonzana Creek Anadarko Source: Company presentations and filings Rex Energy Synergy Bill Barrett Resources HalCon 67 Encana Marcellus - Super Rich Utica - Liquids Rich Niobrara - Wattenberg Eagle Ford - Liquids Rich Mississippian East Marcellus - SW Liquids Rich Utica - Wet Gas Wolfcamp - N. Midland (H) Bone Spring (1st/2nd) NM Eagle Ford - Oil Bone Spring - NM Yeso Wolfcamp - S. Midland (H) Cana Woodford -Oil Bakken Marcellus - NE Wolfberry Uinta - Green River Bone Spring (3rd) - W TX Mississippian West Wolfcamp - N. Delaware (H) Granite Wash - Liquids Rich Marcellus - SW Barnett - Core Fayetteville Three Forks Uinta - Wasatch (V) Cotton Valley Hz Cana Woodford Horn River Basin Barnett Pinedale Piceance Basin Valley Barnett - S. Liquids Rich Eagle Ford - Dry Gas Huron Shale Haynesville - Core LA/TX Woodford - Arkoma IRRs of US Onshore Basins (1) 0% 20% 40% 60% 80% 2,000+ HZ Projects 200+ HZ Projects PDCM 600 HZ Projects 2,200+ Horizontal Liquid-Rich Projects (1) Utilizes futures strip as of 6/17/2013; Source: Credit Suisse Equity Research June 18,

26 Utica: Local Stratigraphic Column Southern Ohio 1. Queenston Shale Classic Mudstone Null TOC & low resistance 2. Upper Utica Shale Mudstone with null limestone content. Some TOC & low resistivity High clay content Lower Youngs Modulus (More Ductile) 3. Point Pleasant Member (Producing) Good TOC & high resistivity Water saturation around 12% Limestone clast s & streaking 4. Lexington & Logana Limestone/shale transitions Prevalent TOC High resistivity 5. Trenton Classic CaCO3 Limestone Gas shows in upper portion 26

27 MCFD Marcellus Horizontal 10,000 Marcellus Well Production Normalized to 5,000' Lateral 1,000 CAPEX: $7 MM $3.50/MCF (Year 1) 100 EUR: 9 BCF Type Curve F&D: $0.72/MCFE IRR: 32% EUR: 7 BCF Type Curve F&D: $0.93/MCFE IRR: 20% EUR: 5 BCF Type Curve F&D: $1.30/MCFE IRR: 11% Harrison County Average Taylor County Average Days 27