CLR Investor Update March 2014

Transcription

1 CLR Investor Update March 2014

2 Forward-Looking Information Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995: This presentation includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of All statements included in this presentation other than statements of historical fact, including, but not limited to, statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, are forward-looking statements. When used in this presentation, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes that the expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, readers should keep in mind the risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors included in the Company's Annual Report on Form 10-K for the year ended December 31, 2013, registration statements and other reports filed from time to time with the Securities and Exchange Commission (SEC), and other announcements the Company makes from time to time. The Company cautions readers that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part I, Item 1A. Risk Factors in the Company's Annual Report on Form 10-K for the year ended December 31, 2013, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that the Company, or persons acting on its behalf, may make. Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements to reflect events or circumstances after the date of this presentation. 2

3 Outstanding Full-Year Execution Full-year 2013 production: 49.6 MMBoe, up 39% over 2012 (71% oil) 144,250 Boe per day in 4Q13: up 35% over 4Q12 Bakken: 93,330 Boe per day, up 38% over 4Q12 SCOOP: 23,750 Boe per day, up 233% over 4Q12 YE13 proved reserves: 1.08 billion Boe, up 38% YOY Achieved record full-year EBITDAX¹ of $2.84 billion: +45% over FY12 EBITDAX¹ ($MM) $712.3 million for 4Q13, up 20% YOY $3,000 $2,840 $2,500 Capital discipline driving value Achieved 2013 capex target of $3.6 billion² $2,000 $1,963 Capex outspend narrowing $1,500 $1,304 Marketing strategy and opex focus drive impressive cash margin³ $1,000 $500 $451 $811 72% cash margin ($49.35 per Boe) in 4Q13 74% cash margin ($53.52 per Boe) for FY13 $ ¹See EBITDAX Reconciliation to GAAP in the Appendix for a reconciliation of net income and operating cash flows to EBITDAX. ²CLR capex guidance excludes acquisition capital. ³See Cost Discipline Driving Excellent Margins in the Appendix for the method of calculating cash margin.

4 Year-End 2013 Proved Reserves 38% Increase in Proved Reserves since YE12: Year-End Reserves are 87% Operated and 68% Crude Oil 1, YE09 YE10 YE11 YE12 YE13 MMBOE 1,200 1,100 1, *Based on internal estimates. 4

5 Rig Count Production (Mboe per day) Drilling Efficiencies Drive Production Growth c ND & MT Rigs Oil (Bo per day) Gas (Boe per day) Total Bakken & Three Forks Rigs: 179 Gas 16% 1,200 1,100 1, Total Bakken & Three Forks Rigs Oil 84% /5/09 7/5/09 1/5/10 7/5/10 1/5/11 7/5/11 1/5/12 7/5/12 1/5/13 7/5/13 1/5/14 5 *Source: North Dakota Industrial Commission, Drilling Info (as of 2/28/2014)

6 Year-End Net Bakken Acres (in thousands) #1 Leaseholder in the Bakken 1.2 million net acres at 3Q13 ~98% HBP on de-risked leasehold at YE2013 ~96% HBP for both de-risked and exploratory leasehold by YE2017 Continental s Acreage Growth 1,400 1,200 1,140 1, Miles 1, Expansion Mode Miles Continental Acreage 6

7 Montana North Dakota There s Only One Bakken: Getting Bigger & Better CLR leading basin-wide efforts to optimize oil recovery 2014 plan: 287 net wells (870 gross) Operating ~22 average rigs in 2014 Density Pilots Update Hawkinson Unit: strong initial production performance Tangsrud, Rollefstad and Wahpeton Units: completing, with full production in 1H14 Hartman, Mack and Lawrence Units: drilling 3,800 square miles of Lower Three Forks productivity delineated LTF Wahpeton** Three Forks Thickness Map 660 WLL LTF Productive Footprint LTF KOG LTF KOG 1,320 LTF LTF LTF LTF 660 LTF LTF 1,320 LTF Tangsrud* Lawrence** LTF 660 1,320 WLL WLL WLL WLL Mack** Rollefstad* Hawkinson* 660 Hartman** 25 Miles WLL 2013 CLR Density Project Industry Density Project CLR LTF Producer Industry LTF Producer 2014 CLR Density Project 7 *1,320 interwell spacing within zone = 320 acre spacing on 2 mile lateral **660 interwell spacing within zone = 160 acre spacing on 2 mile lateral

8 1,320 & 660 Pilot Density Projects: ,320 ft. same-zone spacing 3 project areas: Hawkinson, Tangsrud, and Rollefstad 34 new wells (gross) Micro-seismic monitoring (Hawkinson) 660 ft. same-zone spacing 4 project areas: Wahpeton, Lawrence, Mack, and Hartman 31 new wells (gross) 8

9 Strong Early Performance from Hawkinson Unit Industry landmark: First unique production from 4 different producing intervals spaced 1,320 feet apart Validates CLR vision for full-field development and demonstrates the vast resource potential across CLR s acreage position Strong initial performance in first 120 days Early production suggests 12 of 14 wells show EUR trends exceeding CLR s North Dakota 603 MBoe model by 50% 14,850 Boepd of initial combined production from 14 wells (Oct. 2013) 13,400 Boepd from 11 new wells 1,480 Boepd avg. 24-hour IP: MB & TF1 (4 wells) 1,070 Boepd avg. 24-hour IP: TF2 & TF3 (7 wells) 1,450 Boepd from 3 pre-existing wells 55% working interest in Hawkinson Unit 9

10 Continental Goes Ears Back in Antelope Plan to drill wells over the next five years utilizing mega-pads ~50 wells budgeted for 2014, with large production impact in 2015 Full-field development includes MB, TF1, TF2 and TF3 18 wells in various stages of drilling or completion Devoting 4+ rigs to full field development in operated rigs currently Under-developed area Pipeline infrastructure being expanded 18 Miles Planned 2014 Antelope Mega-Pads Planned 2014 Antelope Multi-Well Pads 10

11 Completed Average Well Costs CLR: The Premier Bakken Operator YE13 operated Bakken well costs were ~$8.0 million per well. Targeting even lower YE14 well costs of ~$7.5 million per operated Bakken well for standard completion design. Millions 2012 Historical 2013 Progress 2014 Operated Target $11 $11.3 Increasing Rates of Return with Lower Average Well Costs $9 $9.2 $9.2-13% from prev. goal -6% from prev. goal $7 $8.0 $7.5 $ Industry 2012 CLR 1H13 Industry 3Q13 CLR YE14 CLR Target *Weighted average well cost, pads and single wells. Well set includes 225 non-operated wells with a CLR interest. CLR wells include artificial lift. 11

12 SCOOP: A New, High-Impact Resource Play South Central Oklahoma Oil Province NW Cana STACK World-class resource shale Up to 400 of oil-rich shale Dual reservoir target Cana Field Excellent siliceous and highly fractured reservoir SCOOP Play validated by 300 industry SCOOP wells 25 Miles Dominant leaseholder: ~400,000 net acres Woodford Shale Thickness 50 ft 100 ft >200 ft Oklahoma Texas 12

13 SCOOP: Continued Exploration and Appraisal 4Q13 net production: 23,750 Boe per day Up 18% sequentially, up 233% over 4Q12 Plan to operate ~18 average rigs in 2014 ~40% of activity to drill extended 2-mile lateral wells 4Q13 average initial rate of 1,300 Boe per day in condensate-rich and oil fairways ~400,000 net acres leased SCOOP Oil, Condensate and Gas Window Map Gas Condensate Oil Well economics continue improving $9.0 million for standard 1-mile lateral wells $13.5 million for standard 2-mile lateral wells Delineation Tests 4Q13 Completions Woodford Completions 35 Miles 13

14 Progress Report for CLR s Five-Year Plan Metrics and Measurements of Success Triple production by 2017 Triple proved reserves by 2017 Exploration: - Confirm lower Three Forks - Expand, de-risk Bakken - Expand, de-risk SCOOP Operating excellence and efficiency Financial flexibility Status/Forecast Objective New yearly target On track to accomplish Should exceed goal 14

15 CLR Clear Vision for Growth Production MMBoe MBoepd MMBoe Proved Reserves MBoepd MBoepd , * Operating excellence with focus on safety and continued cost-efficiency Continue to develop marketing strategy to reach premier markets Unmatched oil growth from existing portfolio with continued exploration Maintain balance sheet strength and flexibility 15 *Midpoint of guidance range.

16 2014 Total Capex Budget: $4.05B¹ Red River Units & Other $143 Capex Breakout Land, Facilities, & Other $510 Key Drilling Areas Net Wells Capex % of Total North Dakota Bakken 240 $2,120 52% Montana Bakken % SCOOP % Red River Units & Other % Subtotal 385 3,540 87% SCOOP $865 Bakken $2,532 Land, Facilities, Workovers, Other % Total Capex¹ ($MM) $4, % Forecasted 2014 Growth Production Growth 26-32% Mid-Point Volume Growth (MMBoe) 14.4 (1) Excludes acquisition capital expenditures. 16

17 MMBOE CLR: Production, Reserve and Stock Growth Annual Proved Production Reserves Share Price 1.08 B 49.6 YE13 17 *Closing stock price as of February 27, 2014

18 Appendix

19 SCOOP One-Mile Lateral Economics Condensate Fairway EUR = 1,190 MBoe (61% liquids)** Gas 39% Gas 25% Oil 24% NGL 37% Oil Fairway EUR = 626 MBoe (75% liquids) ** 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% Rates of Return & Target* Completed Wells Costs Oil Window $9.0MM Oil Window $8.5MM (target) Condensate Window $9.5MM Condensate Window $9.0MM (target) NGL 23% **Expected EUR and Yield Oil 52% 0 $2 $3 $4 $5 $6 Natural Gas Price $/Mcf *Oil Price $90 Gas Diff Premium +85% 19

20 Woodford Eroded SCOOP is Premium Woodford Cana Field SCOOP 100 Upper Woodford Lower Woodford SCOOP = 6X the reservoir volume of Cana Field Oil-prone and liquid-rich Gas Oil Condensate Oil 155 Miles Clay-rich Woodford Silica-rich Woodford Stratigraphic Cross-Section Oil Gas 20

21 Monthly Oil Equiv (MBoe) ROR* Bakken Well Economics 90% 80% 70% 60% 50% 40% 30% 20% 10% $7.5 MM CWC $8.0 MM CWC Crude Oil Price ($/Bbl) Average operated CWC $8.0MM (YE13 target achieved 3 months early) $7.5MM or less YE14 target MBoe EUR ND Bakken Type Curve Months Cum Oil Equiv (MBoe) Oil Equiv (MBoe) *Assumes $7 differential. CWC = Completed Well Cost Cum Oil Equiv (MBoe) 21

22 America s Premium Light Sweet Crude API 45 Crude Quality Sulfur % wt % Improved Refinery Yield % % 70% 60% 50% 40% 30% 20% 10% 0% Distillation Cuts Light Ends Gasoline Jet Fuel Distillate Vac. Resid. Fuel Oil API Sulfur % wt 22

23 How Refiners See Bakken (Relative Netbacks) Product Yield ($/bbl) $ Total Yield ($/bbl) $ $ $ $ Bakken Qua Iboe LLS 40's Blend Hibernia WTI W. Can. Select (WCS) *NYH Product Prices 11/17/2013 based on CLR data and analysis of publicly available crude oil assays 23

24 Refinery Distillation Yields Product Yield ($/bbl) $ $ $80.00 $60.00 $40.00 $20.00 Distillation Cuts Light Ends Gasoline Jet Fuel Distillate Vac. Resid. Fuel Oil $0.00 Bakken Qua Iboe LLS 40's Blend Hibernia WTI W. Can. Select (WCS) *NYH Product Prices 11/17/2013 based on CLR data and analysis of publicly available crude oil assays 24

25 The Market for Bakken Premium Quality Growing faster than production? Seattle New York Cushing Los Angeles Houston 25

26 Production volume (MMBopd) Williston Basin Evacuation Capacity TransCanada East (42") TransCanada Keystone XL High Sierra - Donnybrook Red River - Williston 88 Oil - Guernsey Great Northern - Fryburg World Fuels - NewTown Enbridge - Berthold Plains - Manitou Hess - Tioga Savage - Trenton Rangeland - Epping Musket - Dore Various - Dickinson BOE - Dickinson Plains - Van Hook UET - Beulah Global - Stampede EOG - Stanley Enbridge Sandpiper (24") Pony Express (24") Plains - Bakken North Enbridge ND Enbridge BPEP Tesoro Refinery Butte ND Port - Minot 200 Rig Forecast* 250 Rig Forecast* Bentek Forecast Industry Production Volume as of Oct. 13** Proposed Pipeline 2.0 Rail ,022 MBopd 0.5 Committed Pipeline 0.0 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 *CLR 2013 forecast **ND Pipeline Authority, February 2014 Report 26

27 308 Tight Oil Resource Plays: Larger than We Thought! Prior to Lower TF: 577 BBo in place (2010) 24 BBoe recoverable** 20 BBo (3.5% recovery factor) 320-acre spacing per zone Bakken producer Now: Estimate +57% 903 BBo in place (2012) 32 BBo 3.5% 36 4% 45 5% *The Bakken Petroleum System ranges in thickness from 250 feet to 400 feet **24 BBoe = 20 BBo (3.5%) + 4 BBoe natural gas at 320-acre spacing per zone, (Oct. 2010), not including any reserves from the lower TF benches. 27

28 2014 Operational and Financial Guidance As of February 26, 2014* 2014 Production growth (YOY) 26% to 32% Capital expenditures (non-acquisition) $4.05B Operating Expenses: Production expense per Boe $5.60 to $6.10 Production tax (% of oil & gas revenue) 8% to 9% DD&A per Boe $17.50 to $19.50 G&A expense per Boe $2.00 to $2.50 Non-cash equity compensation per Boe $0.70 to $0.90 Average Price Differentials: NYMEX WTI crude oil (per barrel of oil) ($8.00) to ($11.00) Henry Hub natural gas (per Mcf) +$1.00 to $1.50 Income tax rate 37% Deferred taxes 90% to 95% * No change from previously announced 2014 Guidance Outlook on September 10,

29 Quarterly Cash Flow (Unaudited) Three months ended December 31, Year ended December 31, In thousands Net income $ 132,824 $ 220,511 $ 764,219 $ 739,385 Adjustments to reconcile net income to net cash provided by operating activities: Non-cash expenses 512, ,804 1,809, ,695 Changes in assets and liabilities (60,171) 39,853 (10,875) (13,015) Net cash provided by operating activities 584, ,168 2,563,295 1,632,065 Net cash used in investing activities (911,623) (1,312,243) (3,711,011) (3,903,370) Net cash provided by financing activities 263, ,359 1,140,469 2,253,490 Net change in cash and cash equivalents (63,025) (223,716) (7,247) (17,815) Cash and cash equivalents at beginning of period 91, ,445 35,729 53,544 Cash and cash equivalents at end of period $ 28,482 $ 35,729 $ 28,482 $ 35,729 29

30 Cost Discipline Driving Excellent Margins Q Realized oil price ($/Bbl) $54.44 $70.69 $88.51 $84.59 $84.47 $89.93 Realized natural gas price ($/Mcf) $3.22 $4.49 $5.24 $4.20 $5.49 $5.25 Oil production (Bopd) 27,459 32,385 45,121 68, ,443 95,859 Natural gas production (Mcfpd) 59,194 65, , , , ,355 Total production (Boepd) 37,324 43,318 61,865 97, , ,919 EBITDAX ($000's) (1) $450,648 $810,877 $1,303,959 $1,963,123 $712,300 $2,839,510 Key Operational Statistics (per Boe) (2) Average oil equivalent price (excludes derivatives) $45.10 $59.70 $73.05 $66.83 $68.80 $72.71 Production expense $6.89 $5.87 $6.13 $5.49 $6.03 $5.69 Production tax and other $3.37 $4.82 $6.42 $6.42 $6.35 $6.69 G&A (3) $2.19 $2.35 $2.36 $2.38 $2.27 $2.07 Interest $1.72 $3.34 $3.40 $3.95 $4.80 $4.74 Total cash costs $14.17 $16.38 $18.31 $18.24 $19.45 $19.19 Cash margin $30.93 $43.32 $54.74 $48.59 $49.35 $53.52 Cash margin % 69% 73% 75% 73% 72% 74% 1) See EBITDAX Reconciliation to GAAP in Appendix for a reconciliation of net income and operating cash flows to EBITDAX. 2) Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions. 3) Excludes G&A related to Equity based compensation and relocation expense. 30

31 EBITDAX Reconciliation to GAAP We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. EBITDAX represents earnings (net income) before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows as determined by GAAP. Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because those amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX should not be considered as an alternative to, or more meaningful than, net income or operating cash flows as determined in accordance with GAAP or as an indicator of a company s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our revolving credit facility requires that we maintain a total funded debt to EBITDAX ratio of no greater than 4.0 to 1.0 on a rolling four-quarter basis. This ratio represents the sum of outstanding borrowings and letters of credit under our revolving credit facility plus our note payable and senior note obligations, divided by total EBITDAX for the most recent four quarters. See the following page for reconciliations of our net income and operating cash flows to EBITDAX for the applicable periods. 31

32 EBITDAX Reconciliation to GAAP (cont d) The following tables provide reconciliations of our net income and operating cash flows to EBITDAX for the periods presented: In thousands Q Net income $ 71,338 $ 168,255 $ 429,072 $ 739,385 $ 132,824 $764,219 Interest expense 23,232 53,147 76, ,708 63, ,275 Provision for income taxes 38,670 90, , ,811 78, ,830 Depreciation, depletion, amortization and accretion 207, , , , , ,645 Property impairments 83,694 64, , ,274 58, ,508 Exploration expenses 12,615 12,763 27,920 23,507 5,809 34,947 Impact from derivative instruments: Total (gain) loss on derivatives, net 1, ,762 30,049 (154,016) 102, ,751 Total cash received (paid), net ,495 (34,106) (45,721) (9,644) (61,555) Non-cash (gain) loss on derivatives, net 2, ,257 (4,057) (199,737) 92, ,196 Non-cash equity compensation 11,408 11,691 16,572 29,057 10,431 39,890 EBITDAX $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 712,300 $ 2,839,510 In thousands Q Net cash provided by operating activities $ 372,986 $ 653,167 $ 1,067,915 $ 1,632,065 $ 584,842 $ 2,563,295 Current income tax provision (benefit) 2,551 12,853 13,170 10,517 (4,014) 6,209 Interest expense 23,232 53,147 76, ,708 63, ,275 Exploration expenses, excluding dry hole costs 6,138 9,739 19,971 22,740 5,639 25,597 Gain (loss) on sale of assets, net ,588 20, ,047 (24) 88 Excess tax benefit from stock-based compensation 2,872 5, , Other, net (3,890) (3,513) (4,606) (7,587) 2,020 (1,829) Changes in assets and liabilities 46,050 50, ,949 13,015 60,171 10,875 EBITDAX $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 712,300 $ 2,839,510 32

33 Adjusted Earnings Reconciliation to GAAP Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-gaap financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and corporate relocation expenses. Management believes these measures provide useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity s specific derivative portfolio, impairment methodologies, and nonrecurring transactions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented. In thousands, except per share data Net income (GAAP) Adjustments, net of tax: Non-cash (gain) loss on derivatives, net Property impairments (Gain) loss on sale of assets, net Corporate relocation expenses Adjusted net income (Non-GAAP) Weighted average diluted shares outstanding Adjusted diluted net income per share (Non-GAAP) Three Months Ended December 31, After-Tax $ Diluted EPS After-Tax $ Diluted EPS $ 132,824 $ 0.72 $ 220,511 $ , (4,331) (0.02) 36, , (42,723) (0.23) $ 228,132 $ 1.23 $ 191,801 $ , ,603 $ 1.23 $ 1.04 In thousands, except per share data Net income (GAAP) Adjustments, net of tax: Non-cash (gain) loss on derivatives, net Property impairments (Gain) loss on sale of assets, net Corporate relocation expenses Adjusted net income (Non-GAAP) Weighted average diluted shares outstanding Adjusted diluted net income per share (Non-GAAP) Year Ended December 31, After-Tax $ Diluted EPS After-Tax $ Diluted EPS $ 764,219 $ 4.13 $ 739,385 $ , (123,838) (0.68) 138, , (55) - (84,349) (0.46) 1, , $ 986,125 $ 5.33 $ 611,870 $ , ,846 $ 5.33 $