Continental Resources Reports Third Quarter 2013 Results Hawkinson Unit Density Test Produces at an Initial Combined Rate of 14,850 Boe per Day from Middle Bakken and Three Forks Benches One, Two and Three Adjusted Net Income for Third Quarter 2013 of $297 Million, or $1.61 per Diluted Share Record EBITDAX of $798 Million, an Increase of 13% Compared to Second Quarter 2013 and 62% Compared to Third Quarter 2012 Record Production Totaling 141,900 Boe per Day for Third Quarter 2013, an Increase of 5% Sequentially and 38% Compared to Third Quarter 2012 PR Newswire OKLAHOMA CITY, Nov. 6, 2013 OKLAHOMA CITY, Nov. 6, 2013 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced third quarter 2013 operating and financial results, reporting net income of $167 million, or $0.91 per diluted share. Adjusted net income, which excludes items typically excluded from published analyst estimates, totaled $297 million, or $1.61 per diluted share, an increase of $51 million compared to second quarter 2013. The Company achieved record EBITDAX of $798 million, an increase of $89 million or 13% compared to second quarter 2013. Definitions and reconciliations of adjusted net income, adjusted earnings per share and EBITDAX to the most directly comparable U.S. GAAP financial measures can be found in the supporting tables at the conclusion of this release. (Logo: http://photos.prnewswire.com/prnh/20120327/DA76602LOGO) Third quarter 2013 production highlights include: oRecord net production of approximately 141,900 barrels of oil equivalent ("Boe") per day in third quarter 2013, of which 71% was crude oil; oNet Bakken production increased 7% from second quarter 2013 to approximately 94,500 Boe per day for third quarter 2013, representing 67% of total production, highlighted by Montana production growth of 17% compared to second quarter 2013; and oNet production from South Central Oklahoma Oil Province ("SCOOP") play increased to approximately 20,100 Boe per day for third quarter 2013, up 14% from second quarter 2013. Harold G. Hamm, Continental's Chairman and Chief Executive Officer commented, "The Continental team performed at an exceptional level in the third quarter of this year, increasing production, generating record EBITDAX and delivering on budget. In addition, we completed our first density test in the Hawkinson spacing unit, demonstrating very strong initial production in the Middle Bakken and the first three benches of the Three Forks. Once again, Continental is pioneering the expansion and improved recoveries in the world-class Bakken oil play, demonstrating the productive potential of four to five stacked zones with multiple wells in each." Bakken Delivers Oil Growth Net production from the Company's industry-leading activity in the Bakken play in North Dakota and Montana increased to approximately 94,500 Boe per day in third quarter 2013, an increase of 7% sequentially and 51% above third quarter 2012. The Company's gross operatedBakken production averaged approximately 119,000 Boe per day in third quarter 2013. In the third quarter 2013, Continental operated an average of 20 rigs across its leasehold position of approximately 1.2 million net acres in the Bakken play. The Company participated in completing 75 net (203 gross) wells in third quarter 2013. Given the company's increased activity on large drilling pads, the amount of gross operated wells drilled, but not yet completed increased in third quarter 2013 and is currently 85 wells. Drilling and completion costs continued to improve in the Bakken in the third quarter. Continental's average operated completed well cost in North Dakota is now $8.0 million per well, achieving its revised year-end target two months ahead of schedule. The Company's original operated well cost target for 2013 was $8.2 million per well, which was later reduced to $8.0 million per well. Bakken Downspacing Activity: The Hawkinson Unit In October 2013 and one month ahead of schedule, Continental successfully completed the first of four pilot density projects it has under way. The Hawkinson unit initially tested at a combined rate of 14,850 Boe per day from 14 wells. This included 13,400 Boe per day from 11 new wells drilled this year and combined current rates of 1,450 Boe per day from three existing wells in the unit, which to-date have cumulative production of 1.3 million Boe since 2010. The Hawkinson density project includes four Middle Bakken, three TF1 (Three Forks 1), four TF2 and three TF3 wells, which all were spaced 1,320 feet apart in the same zone and offset 660 feet in the adjacent zones. This is the industry's first density drilling program in the basin to include all of these lower benches. W. F. "Rick" Bott, Continental's President and Chief Operating Officer, commented, "The Hawkinson project is a milestone event for CLR and further validates our vision for full field development of the Bakken –Three Forks reservoirs in this world class oil field. Clearly there is more oil to be recovered than previously perceived and projects like the Hawkinson are leading the way to defining the optimum drilling density and pattern to maximize oil recovery. The news in the Bakken just keeps getting better." In addition to the Hawkinson project, Continental has three other density pilot tests in North Dakota underway, with results expected in the first half of 2014. The Tangsrud project in Divide County involves 12 new wells and the Rollefstad project in McKenzie County involves 11 new wells drilled with 1,320 foot same zone inter-well spacing, similar to the Hawkinson. The Wahpeton project in McKenzie County involves 13 new wells configured in four zones at tighter spacing, which is 660 foot same zone inter-well spacing.During 2014, Continental plans to conduct three additional density pilots to test 660 foot inter-well spacing, further defining the density spacing across a very large portion of Continental's acreage in the Bakken. The Company plans to complete approximately 282 net (761 gross) wells in the Bakken in 2013, including both operated and non-operated wells. The Company estimates its operated rig activity will average 20 rigs throughout the balance of 2013, down from 22 rigs as earlier expected due to realized efficiencies. This activity level should deliver the planned production growth and stay within capital expenditure guidance. Full Development Planned for Antelope – "Ears Back"Program The Antelope prospect area in McKenzie and Williams Counties, North Dakota will be the first area Continental will execute full field development activities in the Bakken as part of the 2013-2014 planned capital program. The Company currently has 40 gross existing producing wells in this area, which includes the recently completed prolific Angus wells and legacy activity at the Rollefstad density pilot. The Company plans to drill an additional 350 wells over the course of the next four to five years focusing on drilling pads with 20 to 30 wells per location. Continental's "Ears Back" project in Antelope will dedicate four rigs in 2014 for full field development with plans to drill Middle Bakken, TF1, TF2 and TF3 wells with 1,320 foot inter-well spacing. Hamm added, "Antelope is a high-impact area where we have been eager to expand our activity, however, we needed to allow regional infrastructure to catch up to support our goal of limited natural gas flaring. We are already leveraging on the success of the Hawkinson project in Antelope with well placement, completion design and facility planning for up to 30 wells on a single location. This areawill be the first in the field to see full field development including the deeper TF benches." Growth in SCOOP Continues Continental continues to deliver excellent, repeatable results from its drilling activity in the SCOOP. The play, discovered by Continental and announced in October 2012, currently extends approximately 3,300 square miles across several counties in Oklahoma and contains defined oil and condensate-rich fairways as delineated by more than 290 gross wells in the area. Continental currently has approximately 320,000 net acres of leasehold in the play. In third quarter 2013, SCOOP net production averaged approximately 20,100 Boe per day, an increase of 14% sequentially and 293% above third quarter 2012. The recent growth was driven by the addition of 11 net (22 gross) operated and non-operated wells in the play during the third quarter 2013, as per the Company's capital plan. The Company is currently operating 12 rigs in the play with plans to increase to 15 by year-end 2013. The Company plans to complete a total of approximately 41 net (77 gross) wells in the SCOOP play in 2013, including both operated and non-operated wells. These wells will focus on expanding the proved productive extent of the play and de-risking the Company's leasehold. Expected net and gross well count activity has been adjusted to account for recent increased cross-unit activity. Production Third quarter 2013 Company net production totaled 13.1 million Boe, or approximately 141,900 Boe per day, a sequential increase of 5% from second quarter 2013. Total net production included approximately 100,700 barrels of oil per day (71% of production) and approximately 247 million cubic feet of natural gas per day (29% of production). In the third quarter 2013, the Company sold its natural gas prior to processing based upon pricing provisions in its natural gas contracts. The Company estimates that if it had sold its natural gas liquids after processing, the combined natural gas liquids and oil would account for approximately 80% of total production. The following table provides the Company's average daily production by region for the periods presented. 3Q 2Q 3Q Boe per day 2013 2013 2012 North Region: North Dakota Bakken 81,545 76,909 55,918 Montana Bakken 12,957 11,081 6,535 Red River Units 14,703 14,886 14,916 Other 408 2,141 1,343 South Region: SCOOP 20,070 17,547 5,108 NW Cana 6,985 7,763 11,395 Arkoma 3,004 3,064 4,061 Other 2,201 2,309 2,590 East Region - - 1,098 Total 141,873 135,700 102,964 Financial Update Continental's average realized sales price excluding the effects of derivative positions was $98.02 per barrel of oil and $5.23 per thousand cubic feet ("Mcf") of natural gas, or $78.55 per Boe for third quarter 2013. Realized settlements of commodity derivative positions generated a $5.92 loss per barrel of oil and $0.62 gain per Mcf of natural gas resulting in a net realized hedging loss of $40.3 million, or $3.11 per Boe for the third quarter 2013. Based on realizations without the effect of derivatives, the Company's third quarter 2013 oil differential was $7.80 per barrel below the NYMEX daily average for the period. The realized natural gas price differential for third quarter 2013 was a positive $1.65 per Mcf. Production expense per Boe was $5.17 for third quarter 2013, an improvement of $0.69 per Boe compared to second quarter 2013. Other select operating costs and expenses for third quarter 2013 included production taxes of 8.2% of oil and natural gas sales; DD&A of $18.87 per Boe; and G&A (cash and non-cash, excluding relocation expenses) of $2.62 per Boe. The Company's 2013 and 2014 guidance can be found at the conclusion of this release. As of September 30, 2013, Continental's balance sheet included approximately $92 million in cash and cash equivalents and an undrawn $1.5 billion revolving credit facility. During third quarter 2013, the Company's long-term corporate credit rating and senior unsecured debt was increased by Standard & Poor's to BBB-, which is investment grade status. As of September 30, 2013, the Company's Net Debt-to-EBITDAX ratio for the trailing four quarters and third quarter 2013 annualized was 1.6 and 1.4 times, respectively. Non-acquisition capital expenditures for third quarter 2013 totaled $910 million, including $770 million in exploration and development drilling, $100 million in leasehold and seismic and $40 million in workovers, recompletions and other. Acquisition capital expenditures totaled approximately $74 million for third quarter 2013, and are excluded from the Company's capital expenditure guidance for 2013 of $3.6 billion. The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes. 3Q 2Q 3Q 2013 2013 2012 Average daily production: Crude oil (Bbl per day) 100,684 96,029 72,235 Natural gas (Mcf per day) 247,135 238,028 184,377 Crude oil equivalents (Boe per day) 141,873 135,700 102,964 Average sales prices, excluding effect from derivatives: Crude oil ($/Bbl) $98.02 $87.22 $82.87 Natural gas ($/Mcf) $5.23 $5.22 $4.00 Crude oil equivalents ($/Boe) $78.55 $71.13 $65.62 Production expenses ($/Boe) $5.17 $5.86 $5.62 Production taxes (% of oil and gas revenues) 8.2% 8.3% 8.4% DD&A ($/Boe) $18.87 $18.88 $19.62 General and administrative expenses ($/Boe) ^(1) $1.81 $2.03 $2.29 Non-cash equity compensation ($/Boe) $0.81 $0.78 $0.78 Net income (in thousands) $167,498 $323,270 $44,096 Diluted net income per share $0.91 $1.75 $0.24 Adjusted net income (in thousands) ^(2) $296,879 $245,728 $159,511 Adjusted diluted net income per share ^(2) $1.61 $1.33 $0.87 EBITDAX (in thousands) ^(2) $797,575 $708,107 $492,279 General and administrative expenses ($/Boe) exclude non-recurring corporate relocation expenses of $0.1 million ($0.01 per Boe) for the (1) three months ended September 30, 2013, $0.7 million ($0.05 per Boe) for the three months ended June 30, 2013, and $2.3 million ($0.24 per Boe) for the three months ended September 30, 2012. Adjusted net income, adjusted diluted net income per share and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income, diluted net income per share, or operating cash flows as determined in (2) accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income, adjusted diluted net income per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. Conference Call Information and Summary Presentation Continental Resources plans to host a conference call to discuss third quarter 2013 results on Thursday, November 7, 2013 at 11 a.m. ET (10 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone: Time and date: 11 a.m. ET, Thursday, November 7, 2013 Dial in: 888 679 8033 Intl. dial in: 617 213 4846 Pass code: 15871985 A replay of the call will be available for 30 days on the Company's website or by dialing: Replay number: 888 286 8010 Intl. replay: 617 801 6888 Pass code: 59553466 Callers who wish to pre-register for the call may go to: https://www.theconferencingservice.com/prereg/key.process?key=PUDQ6BJKE Continental plans to publish a third quarter 2013 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on November 7, 2013. Upcoming Conferences Members of Continental's management team will be participating in the following upcoming investment conferences: November 13, 2013 Jefferies 2013 Global Energy Conference: Houston November 22, 2013 Bank of America Merrill Lynch 2013 Global Energy Conference: Miami December 4, 2013 Cowen and Company Ultimate Energy Conference: New York City December 12, 2013 Capital One Southcoast 2013 Energy Conference: New Orleans The Company's presentations at the above conferences will be available via webcast. Instructions regarding how to access the webcasts andpresentation materials will be available on the Company's website at www.CLR.com on or prior to the day of the presentations. About Continental Resources Continental Resources (NYSE: CLR) is a Top 10 independent oil producer in the United States. Based in Oklahoma City, Continental is the largest leaseholder and producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The company also has significant positions in Oklahoma, including its recently discovered SCOOP play and the Northwest Cana play. With a focus on the exploration and production of oil, Continental is on a mission to unlock the technology and resources vital to American energy independence. In 2013, the company will celebrate 46 years of operation. For more information, please visit www.CLR.com. Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 This press release 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 1934. All statements included in this press release 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 press release, 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 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, 2012, 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 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, 2012, 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 press release 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 press release. CONTACTS: Continental Resources, Inc. Investors Media Warren Henry Kristin Miskovsky VP, Investor Relations VP, Public Relations 405-234-9127 405-234-9480 Warren.Henry@CLR.com Kristin.Miskovsky@CLR.com John J. Kilgallon Director, Investor Relations 405-234-9330 John.Kilgallon@CLR.com Continental Resources, Inc. Unaudited Condensed Consolidated Statements of Income Three months ended September Nine months ended September 30, 30, 2013 2012 2013 2012 Revenues: In thousands, except per share data Crude oil and $ 1,018,784 $ 633,344 $ 2,694,488 $ 1,708,995 natural gas sales Gain (loss) on derivative (203,774) (158,294) (89,548) 144,377 instruments, net Crude oil and natural gas service 8,825 8,679 29,876 30,176 operations Total revenues 823,835 483,729 2,634,816 1,883,548 Operating costs and expenses: Production expenses 67,050 54,210 202,305 138,041 Production taxes 93,282 62,913 247,947 162,880 and other expenses Exploration 8,173 4,899 29,138 17,752 expenses Crude oil and natural gas service 6,654 7,626 22,567 24,723 operations Depreciation, depletion, 244,721 189,374 695,189 499,847 amortization and accretion Property 42,167 27,375 161,960 93,153 impairments General and administrative 34,070 31,925 103,761 86,704 expenses Gain on sale of (325) (115) (112) (67,139) assets, net Total operating 495,792 378,207 1,462,755 955,961 costs and expenses Income from 328,043 105,522 1,172,061 927,587 operations Other income (expense): Interest expense (62,756) (39,205) (171,609) (95,174) Other 584 710 1,765 2,280 (62,172) (38,495) (169,844) (92,894) Income before 265,871 67,027 1,002,217 834,693 income taxes Provision for 98,373 22,931 370,822 315,819 income taxes Net income $ 167,498 $ 44,096 $ 631,395 $ 518,874 Basic net income $ 0.91 $ 0.24 $ 3.43 $ 2.88 per share Diluted net income $ 0.91 $ 0.24 $ 3.42 $ 2.86 per share Continental Resources, Inc. Unaudited Condensed Consolidated Balance Sheets September 30, December 31, 2013 2012 Assets In thousands Current assets $ 1,213,181 $ 946,783 Net property and equipment ^(1) 10,112,506 8,105,269 Other noncurrent assets 94,601 87,957 Total assets $ 11,420,288 $ 9,140,009 Liabilities and shareholders' equity Current liabilities $ 1,468,071 $ 1,125,865 Long-term debt 4,439,825 3,537,771 Other noncurrent liabilities 1,691,779 1,312,674 Total shareholders' equity 3,820,613 3,163,699 Total liabilities and shareholders' equity $ 11,420,288 $ 9,140,009 Balance is net of accumulated depreciation, depletion and amortization of (1) $2.84 billion and $2.12 billion as of September 30, 2013 and December 31, 2012, respectively. Continental Resources, Inc. Unaudited Condensed Consolidated Statements of Cash Flows Three months ended September Nine months ended September 30, 30, 2013 2012 2013 2012 In thousands Net income $ 167,498 $ 44,096 $ 631,395 $ 518,874 Adjustments to reconcile net income to net cash provided by operating activities: Non-cash expenses 558,759 412,006 1,297,762 681,891 Changes in assets 95,251 (79,035) 49,296 (52,868) and liabilities Net cash provided by operating 821,508 377,067 1,978,453 1,147,897 activities Net cash used in investing (949,211) (817,635) (2,799,388) (2,591,127) activities Net cash (used in) provided by (1,203) 670,876 876,713 1,649,131 financing activities Net change in cash and cash (128,906) 230,308 55,778 205,901 equivalents Cash and cash equivalents at 220,413 29,137 35,729 53,544 beginning of period Cash and cash equivalents at end $ 91,507 $ 259,445 $ 91,507 $ 259,445 of period Non-GAAP Financial Measures EBITDAX EBITDAX represents earnings 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 U.S. 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 and operating cash flows in arriving at EBITDAX because these 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 U.S. 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 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 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 the letters of credit under our credit facility plus our note payable and Senior Note obligations, divided by total EBITDAX for the most recent four quarters. Our credit facility defines EBITDAX consistent with the presentation below. The following table provides a reconciliation of our net income to EBITDAX for the periods presented. 3Q 2013 2Q 2013 3Q 2012 in thousands Net income $ 167,498 $ 323,270 $ 44,096 Interest expense 62,756 61,378 39,205 Provision for income taxes 98,373 189,858 22,931 Depreciation, depletion, amortization and 244,721 236,790 189,374 accretion Property impairments 42,167 79,712 27,375 Exploration expenses 8,173 11,151 4,899 Impact from derivative instruments: Total (gain) loss on derivatives, net 203,774 (199,056) 158,294 Total cash paid on derivatives, net (40,349) (4,752) (1,394) Non-cash (gain) loss on derivatives, net 163,425 (203,808) 156,900 Non-cash equity compensation 10,462 9,756 7,499 EBITDAX $ 797,575 $ 708,107 $ 492,279 The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented. 3Q 2013 2Q 2013 3Q 2012 in thousands Net cash provided by operating activities $ 821,508 $ 698,834 $ 377,067 Current income tax provision (benefit) 4,393 5,830 (9,874) Interest expense 62,756 61,378 39,205 Exploration expenses, excluding dry hole 7,055 5,349 4,678 costs Gain (loss) on sale of assets, net 325 (349) 115 Other, net (3,211) 2,539 2,053 Changes in assets and liabilities (95,251) (65,474) 79,035 EBITDAX $ 797,575 $ 708,107 $ 492,279 Adjusted earnings and adjusted earnings per share 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. 3Q 2013 2Q 2013 3Q 2012 In thousands, After-Tax Diluted After-Tax Diluted After-Tax Diluted except per share $ EPS $ EPS $ EPS data Net income (GAAP) $ 167,498 $ $ 323,270 $ $ 44,096 $ 0.91 1.75 0.24 Adjustments, net of tax: Non-cash (gain) $ $ loss on 102,958 0.56 (128,399) (0.69) 97,121 0.53 derivatives, net Property 26,565 $ 50,219 $ 16,945 0.09 impairments 0.14 0.27 (Gain) loss on sale of assets, (205) - 220 - (71) - net Corporate relocation 63 - 418 - 1,420 0.01 expenses Adjusted net $ $ $ income $ 296,879 1.61 $ 245,728 1.33 $ 159,511 0.87 (Non-GAAP) Weighted average diluted shares 184,880 184,739 182,537 outstanding Adjusted diluted $ $ $ net income per 1.61 1.33 0.87 share (Non-GAAP) Continental Resources, Inc. 2013 and 2014 Guidance Outlook As of November 6, 2013* 2013 2014 Production growth (YOY) 38% to 40% 26% to 32% Capital expenditures (non-acquisition) $3.6B $4.05B Operating Expenses: Production expense per Boe $5.60 to $6.00 $5.60 to $6.10 Production tax (% of oil & gas 8% to 9% 8% to 9% revenue)** DD&A per Boe $18.50 to $19.50 $17.50 to $19.50 G&A expense per Boe $2.00 to $2.50 $2.00 to $2.50 Non-cash equity compensation per $0.70 to $0.80 $0.70 to $0.90 Boe Average Price Differentials: NYMEX WTI crude oil (per barrel ($6.00) to ($8.00) ($8.00) to ($11.00) of oil) Henry Hub natural gas (per Mcf) +$1.00 to $1.50 +$1.00 to $1.50 Income tax rate 37% 37% Deferred taxes 90% to 95% 90% to 95% * No change from previously announced 2013 and 2014 Guidance Outlook on September 10, 2013 ** Does not include other expenses which could represent an additional 1% SOURCE Continental Resources Website: http://www.clr.com
Continental Resources Reports Third Quarter 2013 Results
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