Scotia Howard Weil Energy Conference. March 2017

Transcription

1 Scotia Howard Weil Energy Conference March 2017

2 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, forecasts or expectations regarding the Company s business and statements or information concerning the Company s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, 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 these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company s control. No assurance can be given that such expectations will be correct or achieved or the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial, market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas exploration, drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other revenue-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A Risk Factors and elsewhere in the Company s Annual Report on Form 10-K for the year ended December 31, 2016, 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 on which such statement is made. 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. Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this presentation, or otherwise. Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates. We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.

3 3 Continental Resources Celebrating 50 Years of Organic Growth Play Net Acres NORTH Bakken: ~848,000 STACK: STACK Meramec ~1.78 Million Net Reservoir Acres SOUTH Meramec ~200,000 Woodford ~185,000 SCOOP Springer SCOOP: Springer ~200,000 SCOOP Woodford Woodford ~346,000 Anadarko Woodford Arkoma Woodford BAKKEN 250, , , , , , ,000 Boepd Cedar Hills MT Bakken ND Bakken STACK 75, ,000 SCOOP 25,

4 4 Performance Taken to New Level Last 2 Years Structural Improvements Benefiting 2017 and Beyond $/Boe $10 $8 $6 $4 $2 Production and Cash G&A Costs $7.87 $7.76 $7.64 $2.38 $2.07 $2.06 $6.00 $5.18 $1.70 $1.53 $5.49 $5.69 $5.58 $4.30 $3.65 (1) 2016 vs 2014 Capital efficiency (2) UP ~175% EUR/operated well UP ~100% Production expense & cash G&A (1) DOWN ~32% $ (1) Production Expense Cash G&A EUR Per Operated Well Key Drivers MBoe 1,600 1,400 1,200 1, Boe/$1k Boe/$1k Boe/$1k 1, , Boe/$1k Boe/$1k Boe/$1k Net Boe/$1,000 (2) Added STACK Moved to Bakken core Enhanced completions Operating efficiencies 1. See Cash G&A Reconciliation to GAAP on slide 23 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-gaap measure 2. Capital efficiency based on reserves developed per dollar invested; average net revenue interest of 82% assumed for net capital efficiency

5 2017: Disciplined Growth Targeting 20%+ Increase in Production by Year End 5 $1.95 billion capital budget (~90% D&C) 20 rigs vs. 19 rigs in 2016 ~11 stim crews vs. ~4 stim crews in 2016 Over 2X more operated completions than 2016 Oil-weighted production growth Targeting 250,000 to 260,000 Boepd 2017 exit rate 82% of D&C capex allocated to Bakken & STACK (75% oil) No new debt Capital budget cash flow neutral at $55 WTI and $3.14 gas Targeting over $600 million of additional non-strategic asset sales in 2017 Momentum carries into 2018 ~72 Bakken stimulated wells waiting on first production at year-end 2017 Targeting 290,000 to 310,000 Boepd 2018 exit rate

6 Capital Focused on High ROR Oil Plays Play Capital ($ in MM) (1) % of D&C Budget (2) (3) Est. Total ROR % Oil % Liquids (4) Bakken DUCs $550 32% 100%+ 80% 90% Bakken Drilling $490 28% ~40% 80% 90% (6) STACK $375 22% 100%+ 60% 70% (7) SCOOP $245 14% ~55% 20% 55% (8) (5) NW Cana $60 4% 100%+ 2% 20% Total D&C Program (weighted avg) Non-D&C Capital (land, facilities, other) $1, % - 58% 73% 82% of D&C capex allocated to Bakken and STACK (75% oil) $ Total 2017 Capital $1, Inclusive of capital for outside operated activity, except for Bakken DUCs 2.At $55 WTI and $3.50 gas, see footnote 1 on slide 11 3.Based upon 2-stream oil volumes at the wellhead 4.Based upon theoretical NGL recoveries after processing 5.ROR is on the incremental cost forward cost of completion 6.STACK ROR is based on STACK over-pressured oil wells 7.SCOOP ROR is based on SCOOP Woodford condensate wells 8.NW Cana as part of the JDA with SK E&S

7 2017 Sets Up Multi-Year Double-Digit Growth Fourth Quarter Production Chart Annual Production Chart Boe per day 500, , , , , , , ,000 STACK SCOOP Bakken Legacy ~210,000 ~255,000 (Exit rate) Boe per day 450, , , , , , ,000 STACK SCOOP Bakken Legacy ~225,000 (Midpoint) 9% 100, ,000 50,000 50, Q Q 2017E 4Q 2018E 4Q 2019E 4Q 2020E E 2018E 2019E 2020E Production guidance: 2017 exit rate: 250,000 to 260,000 Boe per day 2018 exit rate: 290,000 to 310,000 Boe per day Oil production growing to 60%-65% of total production 7

8 Completion Technology Continues to Increase Well Performance in all Plays 8 Cum Boe 120,000 80,000 40,000 0 Bakken Bakken Enhanced completions average Bakken Enhanced Type Curve (980 MBoe) 90 days 35% higher than type curve Days Higher proppant loads Increased fluid volumes Shorter stage lengths More aggressive flowbacks and lift 200,000 SCOOP Woodford Oil SCOOP Woodford Condensate Cum Boe 150, ,000 50,000 SCOOP Enhanced completions SCOOP Offsets SCOOP Enhanced Type Curve (1,340 MBoe) 180 days 30% Uplift Cum Boe 450, , ,000 SCOOP Enhanced Completions SCOOP Offsets SCOOP Enhanced Type Curve (2,300 MBOE) 180 days 45% Uplift Days Days

9 9 STACK Expansion Continues with Excellent Results 200,000 net acres ~98% in over-pressured window ~40% oil, ~30% liquids-rich, ~30% gas ~1,500 potential net unrisked drilling locations Intermediate pipe required Wells Drilling / Completing Over- Pressured Normally- Pressured 7 completions announced 4Q16 1,600 2,500 Boepd 24-hr IPs 55%-73% oil As of late February, 35 operated wells in progress 12 rigs drilling (7 Meramec, 5 Woodford) CLR Meramec producing wells CLR Meramec wells drilling / completing Industry Meramec well Industry Rigs CLR Rigs CLR Leasehold

10 10 STACK 2017 Drilling Program Focused on Density Development and Play Expansion ~47,000 net acres under development in oil window ~55 operated units ~60% operated working interest 6 units scheduled for units in oil window De-risked portion of overpressured oil window Density Activity 6 units scheduled for unit in condensate window Testing 4 to 6 wells per zone Unit efficiencies further uplift economics 1.Pre-tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation. ROR CLR Meramec producing wells CLR Meramec wells drilling / completing Industry Meramec well Industry Rigs CLR Rigs CLR Leasehold 100% 80% 60% 40% STACK Over-Pressured Oil $9.0MM Budget standalone 2017 CWC $7.8MM Budget density CWC 20% Target EUR: 1,700 MBOE Avg. Lateral: 9,800 0% $30 $40 $50 $60 $70 WTI Oil Price, $/BBL

11 Outstanding First STACK Density Test in Meramec Over-Pressured Oil Window 11 21,354 Boe per day (70% oil) from 8 Meramec wells (combined peak 24-hour rates) 710 CLR: Ludwig Density 1 Mile 1, MICROSEISMIC SURVEY 175 Upper Meramec Middle Meramec Lower Meramec Osage Woodford Hunton Efficiency gains: New Well Parent Well 30% reduction in CWC ($7.8 million) 36% reduction in drill time (25 days) Ludwig Daily Production (1) 1. Normalized to 9,800 lateral Boepd 1000 Parent well 7 New wells 1,700 MBoe type curve Days on Production

12 12 SCOOP Woodford Condensate Enhanced Stimulations Uplift EURs Another 15% EUR 2,300 MBoe per well (7,500 lateral) Up from 2,000 MBoe EUR 80% ROR (1) for $10.3 million CWC Two completions announced 4Q 2016: 3,547 and 3,463 Boepd 24-hr IPs 26% and 29% oil 3,220 and 3,160 psi flowing casing pressure Peppered Ranch Boatright 100% 80% SCOOP Woodford Condensate Target EUR: 2,300 MBOE Avg. Lateral: 7,500 ~80% ROR ROR 60% 40% 20% $10.3MM Budget 2017 (2,300 MBOE) 0% $2 $3 $4 Gas Price, $/MCF 1. Assumes $55 oil and $3.50 gas. Pre-tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation. 12 Miles CLR Leasehold CLR Enhanced Completion Woodford HZ Producing Well Gas Condensate Oil

13 13 Three Record CLR Bakken Wells in Last Two Quarters Larger stimulations and more aggressive flowback resulted in record 30-day rates: Brangus North, Holstein Federal & Rath Federal Wells performing above 980 MBoe type curve (1) 120,000 (initial wells on unit) Larger enhanced completions well locations Maryland 2-16H IP: 1,264 Boe MB & TF1 Holstein Federal 13-25H IP: 2,718 Boe MB, TF1, TF2 Charolais North 1-31H1 IP: 2,761 Boe Brangus North 1-2H2 IP: 2,493 Boe 100,000 80,000 Cum Boe 60,000 40,000 20, Normalized Days 90 days 35% higher than type curve MB or TF1 Nashville 2-21H IP: 1,417 Boe 50 Miles CLR Leasehold MB & TF1 CLR Larger Enhanced Completion MB, TF1, TF2, TF3 Rath Federal 5-22H IP: 2,395 Boe MB or TF1 Corsican Federal 1-15H IP: 1,836 Boe Note: Larger enhanced completions defined by 7 initial unit wells with greater than 720 lb/ft proppant 1. Normalized to 9,800 lateral

14 14 Harvesting Uncompleted Bakken Wells Underway ~148 Bakken wells to be completed in 2017 (90% drilled but uncompleted) Uncompleted well locations Average 7 operated stimulation crews ~72 additional wells stimulated at year-end 2017 with first sales in % 80% Drilling Target EUR: 920 MBOE DUC EUR: 980 MBOE Avg. Lateral: 9,800 Bakken ~100% ROR ROR 60% 40% 20% ~40% ROR $4.9MM DUC Budget 2017 (980 MBOE) (1) $7MM Drilling Budget 2017 (920 MBOE) 0% $40 $50 $60 $70 WTI Oil Price, $/BBL 50 Miles CLR Leasehold CLR YE 2016 uncompleted well Note: Pre-tax rate of return (ROR) is based on projected cash flow and time value of money; costs include completed well cost, production expense, severance tax and variable operating costs. $3.50 gas is used for oil price sensitivities and $55 WTI is used for gas price sensitivities. The description of the ROR calculation applies to any ROR reference appearing in this presentation. 1.$4.9 MM gross cost forward incremental completion cost

15 Bakken Differentials Improving with Added Pipeline Takeaway Capacity 15 3,500 Bakken Takeaway Capacity More than 90% of CLR Bakken barrels on pipe 3,000 Thousand Bopd 2,500 2,000 1,500 1, Pipe Rail EST With completion of DAPL, pipeline takeaway capacity should exceed production in 2017 Basin differentials may drop by $2 or more Local Refining Pipeline Rail Bakken Production North Dakota Pipeline Authority and CLR estimates

16 Low Costs (1) Competitively Positions CLR in Any Environment 16 Avg. Realized $/Boe (3) $80 $70 $60 $50 $40 $30 $20 $10 $0 $59.35 $43.32 $44.68 $ % 69% $3.40 $3.34 $3.95 $4.74 $4.49 $1.72 $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.19 $72.45 $72.04 $54.74 $65.99 $53.52 $66.53 $48.59 $ % 74% 74% 73% $2.35 $2.36 $2.38 $2.07 $2.06 $31.48 $25.55 $ % $2.47 $1.79 $1.70 $1.53 $6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $3.65 $3.86 $ % $4.04 $11.01 per Boe Production Expense Cash G&A (2) Production/Severance Tax & Other Interest Margin (1) 1. Margin presented on this slide represents the Company s average sales price for a period expressed in barrels of oil equivalent (Boe) less production expenses, production taxes, G&A expenses (exclusive of non-cash equity compensation expenses), and interest expense, all expressed on a per-boe basis. Margin does not reflect all activities of the Company that give rise to cash inflows and outflows and specifically excludes income and costs associated with derivative settlements, service operations, exploration activities, asset dispositions, and various non-operating activities. These items are excluded from the computation of Margin because they can vary significantly from period to period in a manner that does not correlate with changes in the Company s production and sales volumes. Therefore, these items are not typically utilized by management on a per-boe basis in assessing the performance of the Company s E&P operations from period to period. See Continuing to Deliver Strong Margins on slide 19 for additional details on the method for calculating margin. 2. See Cash G&A Reconciliation to GAAP on slide 23 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-gaap measure. 3. Based on average oil equivalent price (excluding derivatives and including natural gas.)

17 17 Continental Resources - In Closing Depth and quality of inventory has never been better Capital efficiencies at all-time high Production expense and cash G&A among the lowest in the E&P space Debt reduced by ~$600 million in 2016 ~20% projected production growth (exit-rate 2017 over 4Q 2016) 82% of 2017 D&C capex focused on oil-weighted Bakken and STACK Targeting debt reduction by another ~$600 million in 2017 through nonstrategic asset sales

18 APPENDIX 18

19 Continuing to Deliver Strong Margins (1) Q Realized oil price ($/Bbl) $54.44 $70.69 $88.51 $84.59 $89.93 $81.26 $40.50 $42.23 $35.51 Realized natural gas price ($/Mcf) $2.95 $4.26 $4.87 $3.73 $4.87 $5.40 $2.31 $2.70 $1.87 Oil production (Bopd) 27,459 32,385 45,121 68,497 95, , , , ,005 Natural gas production (Mcfpd) 59,194 65, , , , , , , ,442 Total production (Boepd) 37,324 43,318 61,865 97, , , , , ,912 EBITDAX ($000's) (2) $450,648 $810,877 $1,303,959 $1,963,123 $2,839,510 $3,776,051 $1,978,896 $652,382 $1,881,889 Key Operational Statistics (per Boe) (3) Average oil equivalent price (excludes derivatives) $44.68 $59.35 $72.45 $65.99 $72.04 $66.53 $31.48 $30.64 $25.55 Production expense $6.89 $5.87 $6.13 $5.49 $5.69 $5.58 $4.30 $3.60 $3.65 Production tax and other $2.95 $4.47 $5.82 $5.58 $6.02 $5.54 $2.47 $1.98 $1.79 Cash G&A (4) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $2.21 $1.53 Interest $1.72 $3.34 $3.40 $3.95 $4.74 $4.49 $3.86 $3.92 $4.04 Total of selected costs $13.75 $16.03 $17.71 $17.40 $18.52 $17.67 $12.33 $11.71 $11.01 Margin (1) $30.93 $43.32 $54.74 $48.59 $53.52 $48.86 $19.15 $18.93 $14.54 Margin % 69% 73% 76% 74% 74% 73% 61% 62% 57% 1. Margin represents the Company s average sales price for a period expressed in barrels of oil equivalent (Boe) less production expenses, production taxes, G&A expenses (exclusive of non-cash equity compensation expenses), and interest expense, all expressed on a per-boe basis. Margin does not reflect all activities of the Company that give rise to cash inflows and outflows and specifically excludes income and costs associated with derivative settlements, service operations, exploration activities, asset dispositions, and various non-operating activities. These items are excluded from the computation of Margin because they can vary significantly from period to period in a manner that does not correlate with changes in the Company s production and sales volumes. Therefore, these items are not typically utilized by management on a per-boe basis in assessing the performance of the Company s E&P operations from period to period. 2. See EBITDAX reconciliation to GAAP on slide 35 for a reconciliation of GAAP net income and net cash provided by operating activities to EBITDAX, which is a non-gaap measure. 3. Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions. 4. See Cash G&A Reconciliation to GAAP on slide 37 for a reconciliation of GAAP Total G&A per Boe to Cash G&A per Boe, which is a non-gaap measure. 19

20 20 EBITDAX Reconciliation to GAAP We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings (net income (loss)) 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, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or net cash provided by operating activities 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. Further, 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. We exclude the items listed above from net income (loss) and net cash provided by operating activities 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 (loss) or net cash provided by operating activities 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. See the following page for reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the applicable periods.

21 EBITDAX Reconciliation to GAAP The following tables provide reconciliations of our net income (loss) and net cash provided by operating activities to EBITDAX for the periods presented: In thousands Q Net income (loss) $ 71,338 $ 168,255 $ 429,072 $ 739,385 $ 764,219 $ 977,341 $ (353,668) $ 27,670 $ (399,679) Interest expense 23,232 53,147 76, , , , ,079 75, ,562 Provision (benefit) for income taxes 38,670 90, , , , ,697 (181,417) 26,478 (232,775) Depreciation, depletion, amortization and accretion 207, , , , ,645 1,358,669 1,749, ,321 1,708,744 Property impairments 83,694 64, , , , , ,131 34, ,292 Exploration expenses 12,615 12,763 27,920 23,507 34,947 50,067 19,413 8,246 16,972 Impact from derivative instruments: Total (gain) loss on derivatives, net 1, ,762 30,049 (154,016) 191,751 (559,759) (91,085) 45,331 67,099 Total cash received (paid), net ,495 (34,106) (45,721) (61,555) 385,350 69,553 6,281 89,522 Non-cash (gain) loss on derivatives, net 2, ,257 (4,057) (199,737) 130,196 (174,409) (21,532) 51, ,621 Non-cash equity compensation 11,408 11,691 16,572 29,057 39,890 54,353 51,834 13,823 48,097 Loss on extinguishment of debt , ,055 26,055 EBITDAX (non-gaap) $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 652,382 $ 1,881,889 In thousands Q Net cash provided by operating activities $ 372,986 $ 653,167 $ 1,067,915 $ 1,632,065 $ 2,563,295 $ 3,355,715 $ 1,857,101 $ 262,031 $ 1,125,919 Current income tax provision (benefit) 2,551 12,853 13,170 10,517 6, (22,941) (22,939) Interest expense 23,232 53,147 76, , , , ,079 75, ,562 Exploration expenses, excluding dry hole costs 6,138 9,739 19,971 22,740 25,597 26,388 11,032 3,613 12,106 Gain on sale of assets, net ,588 20, , , , ,489 Tax benefit (deficiency) from stock-based compensation 2,872 5, , ,177 (368) (9,828) Other, net (3,890) (3,513) (4,606) (7,587) (1,829) (17,279) (10,044) (1,613) (10,636) Changes in assets and liabilities 46,050 50, ,949 13,015 10, ,679 (228,622) 134, ,216 EBITDAX (non-gaap) $ 450,648 $ 810,877 $ 1,303,959 $ 1,963,123 $ 2,839,510 $ 3,776,051 $ 1,978,896 $ 652,382 $ 1,881,889 21

22 22 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 losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. 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 property dispositions. 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 tables reconcile 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. 4Q Q In thousands, except per share data $ Diluted EPS $ Diluted EPS $ Diluted EPS $ Diluted EPS Net income (loss) (GAAP) $ 27,670 $ 0.07 $ (139,677) $ (0.38) $(399,679) $ (1.08) $(353,668) $ (0.96) Adjustments: Non-cash (gain) loss on derivatives 51,612 4, ,621 (21,532) Property impairments 34,564 81, , ,131 Gain on sale of assets (201,315) (218) (304,489) (23,149) Loss on extinguishment of debt 26,055-26,055 Total tax effect of adjustments 33,998 (32,229) (42,448) (119,307) Total adjustments, net of tax (55,086) (0.14) 53, , , Adjusted net income (loss) (Non-GAAP) $ (27,416) $ (0.07) $ (86,644) $ (0.23) $ (326,648) $ (0.88) $ (115,525) $ (0.31) Weighted average diluted shares outstanding 370, , , ,540 Adjusted diluted net income (loss) per share (Non-GAAP) $ (0.07) $ (0.23) $ (0.88) $ (0.31)

23 Cash G&A Reconciliation to GAAP Our presentation of cash general and administrative ( G&A ) expenses per Boe is a non-gaap measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses and corporate relocation expenses, expressed on a per-boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe 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 total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented Q Guidance Total G&A per Boe (GAAP) $3.03 $3.09 $3.23 $3.42 $2.91 $2.92 $2.34 $2.93 $2.14 $ $2.70 Less: Non-cash equity compensation per Boe ($0.84) ($0.74) ($0.73) ($0.82) ($0.80) ($0.86) ($0.64) ($0.72) ($0.61) ($0.60) ($0.70) Less: Relocation expenses per Boe - - ($0.14) ($0.22) ($0.04) Cash G&A per Boe (non-gaap) $2.19 $2.35 $2.36 $2.38 $2.07 $2.06 $1.70 $2.21 $1.53 $ $