Continental Resources Reports First Quarter 2013 Results Record Production Totaling 121,500 Boe per Day for First Quarter 2013, an Increase of 14% Sequentially and 42% Compared to First Quarter 2012 Company Reports Adjusted Net Income for First Quarter 2013 of $215 Million, or $1.17 per Diluted Share; Record EBITDAX of $622 Million, an Increase of 5% Compared to Fourth Quarter 2012 and 37% Compared to First Quarter 2012 Three Recent Successful Lower Three Forks Completions Announced; SCOOP Production Doubles Quarter over Quarter on Strong Wells PR Newswire OKLAHOMA CITY, May 8, 2013 OKLAHOMA CITY, May 8, 2013 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced first quarter 2013 operating and financial results, reporting net income of $141 million, or $0.76 per diluted share. Adjusted net income, which excludes items typically excluded from published analyst estimates, totaled $215 million, or $1.17 per diluted share. EBITDAX reached a record level of $622 million, an increase of $27 million or 5% compared to fourth quarter 2012. 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) Significant first quarter 2013 operational highlights: oAchieved record net production of approximately 121,500 barrels oil equivalent ("Boe") per day in first quarter 2013, which includes 71% crude oil; oNet Bakken production increased to approximately 76,900 Boe per day for first quarter 2013, representing 63% of total production. Gross operated Bakken production surpassed a significant milestone, averaging more than 100,000 Boe per day for first quarter 2013; oThree recent successful Lower Three Forks completions expand the potential aerial extent of productivity and are performing in-line with similar Middle Bakken and Upper Three Forks wells in the surrounding areas; oAhead of plan to reduce operated Bakken averagewell costs to $8.2 million by year-end 2013, current operated well costs are approximately $8.3 million; and oNet production from South Central Oklahoma Oil Province ("SCOOP") play increased to approximately 14,200 Boe per day, up 100% from fourth quarter 2012 and up 462% from first quarter 2012. "We are off to an excellent start in 2013 in executing our strategy of profitably growing our world-class position in the Bakken, testing the lower benches and downspacing capability, and also delineating our exciting new play, SCOOP," said Harold G. Hamm, Continental's Chairman and Chief Executive Officer. "Our focus on driving well costs lower has been successful due to enhanced utilization of pad drilling, improved cycle times and supply chain efforts. We intend to maintain our capital spending discipline this year, as evident in our first quarter results." Production, Realizations and Expenses First quarter 2013 net production totaled 10.9 million Boe, or approximately 121,500 Boe per day, a sequential increase of 14% from fourth quarter 2012. Total production included approximately 86,100 barrels of oil per day (71% of production) and approximately 212.8 million cubic feet of natural gas per day (29% of production). While the Company currently sells 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 Company's combined natural gas liquids and oil would account for approximately 80% of total production. Continental's average realized sales price excluding the effects of derivative positions was $89.99 per barrel of oil and $4.99 per thousand cubic feet ("Mcf") of natural gas, or $72.31 per Boe. Realized settlements of commodityderivative positions generated a $1.24 loss per barrel of oil and $0.14 gain per Mcf of natural gas resulting in a net realized hedging loss of $6.8 million, or $0.63 per Boe for the first quarter 2013. Based on realizations without the effect of derivatives, the Company's first quarter 2013 oil differential, as compared to the NYMEX daily average for the period, was a negative $4.29 per barrel, favorable to annual guidance of negative $5.00 to $7.00 per barrel. The natural gas differential for first quarter 2013 was a positive $1.65 per Mcf of natural gas, favorable to annual guidance range of positive $1.00 to $1.50 per Mcf. Production expense per Boe was $5.70 for first quarter 2013, sequentially below $5.90 per Boe from fourth quarter 2012, but above annual guidance range of $5.20 to $5.60 per Boe, due to typical winter weather temporarily impacting production costs in certain areas. The Company expects per unit production expense to decrease throughout a majority of the remainder of the year. Other select operating costs and expenses for first quarter 2013 were as follows: production taxes 8.2% of oil and natural gas sales; DD&A $19.72 per Boe and G&A (cash and non-cash, excluding relocation expenses) $3.05 per Boe, all within the range of the Company's annual guidance. The Company's 2013 guidance can be found on the last page of this release and remains unchanged from previous guidance provided on February 27, 2013. W. F. "Rick" Bott, Continental's President and Chief Operating Officer, added, "Our production growth remained strong despite seasonal challenges in the Bakken. Our realizations remain on track, driving an impressive 74% cash margin, which benefited from 80% of our operated Bakken production being transported by rail as we continue to access markets on all US coasts. We continue to monitor oil differentials and transportation costs to ensure we realize the most attractive pricing for our premium Bakken oil." The following table provides the Company's average daily production by region for the periods presented. 1Q 4Q 1Q Boe per day 2013 2012 2012 North Region: North Dakota Bakken 67,575 59,019 41,895 Montana Bakken 9,352 8,503 6,129 Red River Units 15,055 14,716 15,415 Other 1,267 967 1,445 South Region: SCOOP 14,243 7,123 2,533 NW Cana 8,323 9,716 10,293 Arkoma 3,234 3,225 3,637 Other 2,483 2,556 2,988 East Region - 1,006 1,191 Total 121,532 106,831 85,526 The following table provides production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses are calculated using sales volumes. 1Q 4Q 1Q 2013 2012 2012 Average daily production: Crude oil (Bbl per day) 86,071 76,449 59,901 Natural gas (Mcf per day) 212,766 182,289 153,751 Crude oil equivalents (Boe per day) 121,532 106,831 85,526 Average sales prices, excluding effect from derivatives: Crude oil ($/Bbl) $89.99 $84.99 $90.58 Natural gas ($/Mcf) $4.99 $4.82 $4.48 Crude oil equivalents ($/Boe) $72.31 $68.89 $71.39 Production expenses ($/Boe) $5.70 $5.90 $5.18 Production taxes (% of oil and gas revenues) 8.2% 8.3% 8.1% DD&A ($/Boe) $19.72 $19.76 $19.32 General and administrative expenses ($/Boe) ^(1) $2.20 $2.70 $2.29 Non-cash equity compensation ($/Boe) $0.85 $0.85 $0.71 Net income (in thousands) $140,627 $220,511 $69,094 Diluted net income per share $0.76 $1.19 $0.38 Adjusted net income (in thousands) ^(2) $215,386 $191,801 $137,900 Adjusted diluted net income per share ^(2) $1.17 $1.04 $0.76 EBITDAX (in thousands) ^(2) $621,528 $594,452 $454,532 General and administrative expenses exclude non-recurring corporate (1) relocation expenses of $0.7 million ($0.06 per Boe) for first quarter 2013, $0.5 million ($0.05 per Boe) for fourth quarter 2012 and $1.7 million ($0.23 per Boe) for first quarter 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. Financial Update At March 31, 2013, Continental's balance sheet included approximately $59 million in cash and cash equivalents and approximately $4.0 billion in total debt, which included approximately $1.0 billion borrowed under the Company's revolving credit facility. On April 5, 2013, Continental completed a $1.5 billion, 4½ % senior unsecured notes offering, which matures in 2023. Proceeds from the offering were applied to fully repay borrowings under the credit facility and for future development and exploratory drilling. Non-acquisition capital expenditures for first quarter 2013 totaled approximately $899 million, including $792 million in exploration and development drilling, $84 million in leasehold and seismic and $23 million in workovers, recompletions and other. Acquisition capital expenditures totaled approximately $22 million for first quarter 2013, and are excluded from the Company's capital expenditure guidance for 2013 of $3.6 billion. John D. Hart, Continental's Chief Financial Officer, added, "Our recent notes offering was highly successful, and our focus on cost reduction and efficiency gains is on schedule to keep us in-line with our capital expenditure guidance. Our significant production growth and consistent top-tier cash margins per Boe allow us to self-fund a larger portion of our planned activity." Strong Bakken Production Growth Net production from the Company's activity in the Bakken play in North Dakota and Montana increased to approximately 76,900 Boe per day in first quarter 2013, an increase of 14% sequentially and 60% above first quarter 2012. The Company's gross operated average production in first quarter 2013in the Bakken reached a milestone of more than 100,000 Boe per day. Continental operated 22 rigs across its industry-leading leasehold position of approximately 1.2 million net acres in the Bakken play. The Company participated in completing 66 net (162 gross) wells in first quarter 2013, which included 21 gross wells deferred from fourth quarter 2012. The Company's Bakken backlog of gross wells drilled, but not yet completed, is currently 80 gross wells, which is down from fourth quarter 2012, however is expected to grow at various times of the year due to increased utilization of pad drilling. Development drilling and completion activity for first quarter 2013 continued to meet expectations. In North Dakota, Company-operated wells completed during first quarter 2013 averaged an initial one-day test of 1,125 Boe per day, which included 84% oil. Company-operated Montana wells completed during first quarter 2013 averaged an initial one-day test of 670 Boe per day, which included 87% oil. These results are consistent with the Company's estimated ultimate recovery ("EUR") models of 603,000 Boe for North Dakota wells and 430,000 Boe for Montana wells. Continental continues to make progress on its 22-well Lower Three Forks exploratory program, which is testing the productive extent of the lower benches. Initial 24-hour flow rates from Lower Three Forks tests for first quarter 2013 included the Barney 2-29H-2 well, which is a second-bench test and had an initial flow rate of 1,075 Boe per day. The well is located 16 miles north of the Company's Charlotte pad. At the Company-operated Stedman pad, located on the western flank of the play near the North Dakota and Montana border and 35 miles northwest of the Charlotte pad, the Stedman 2-24H-2 well, a second-bench test flowed at an initial rate of 1,030 Boe per day. Additionally, the Stedman 3-24H-3 well, a third-bench test had initial one-day production of 465 Boe. Inclusive of these wells, the Company currently has six producing wells in the lower benches with average initial production rates of approximately 1,170 Boe per day. On average, these six wells are performing in-line with typical Middle Bakken and Three Forks first-bench wells in their respective areas. The following table summarizes the Company's Lower Three Forks activity: Lower Three Forks Exploration Well Status Zone Drilling Completing Producing To Be Drilled Total TF1 1 3 4 TF2 2 1 4 4 11 TF3 3 2 5 TF4 2 2 Total 2 7 6 7 22 Data in table includes two wells drilled in 2012 and 20 wells drilled or planned in 2013 Cumulative approximate production from the Company's initial lower bench tests include 116,000 Boe from the Charlotte 2-22H well, a second-bench test of 18 months; 55,000 Boe from the Charlotte 3-22H well, a third-bench test of 5.5 months; and 53,000 Boe from the Angus 2-9H-2 well, a second-bench test of 2 months. The Company's other Bakken exploration and appraisal initiative involves four pilot density projects to test 320-acre and 160-acre spacing in the Middle Bakken and first three benches of the Three Forks. The Company plans to complete 47 gross wells in the pilot density program, to help determine the optimum well spacing and pattern to maximize the ultimate recovery from the multiple Bakken and Three Forks reservoirs. Continental has drilled eight wells and is currently drilling the ninth on its first 320-acre pilot density project at the Hawkinson pad in Dunn County. Drilling is under way on the 13-well, 160-acre pilot on the Wahpeton pad in McKenzie County and the 12-well, 320-acre pilot on the Tangsrud pad in Divide County. One additional 320-acre pilot at the Rollefstad pad is scheduled to spud in the second half of 2013. In summary, of the 47-well pilot density program, 10 wells are currently in the drilling stage, 10 wells are waiting on completion and 27 wells have yet to be drilled. Once each pad has reached initial production, the wells will be announced together as part of the quarterly results. The Company plans to complete 245 net (790 gross) wells in the Bakken in 2013, including both operated and non-operated wells. Due to efficiency gains, the Company plans to reduce operated rig activity to an average of 20 rigs through the balance of the year, whichshould deliver the planned production growth and keep within capital expenditure guidance. Mr. Bott added, "Quarter after quarter, our Bakken operations continue to deliver impressive growth with highly attractive returns. On the exploration front, we are very excited about the continual success of our Lower Three Forks productivity tests. Our cost focus has put us ahead of target on reducing average drilling and completion well costs in the Bakken. Based on field estimates, we are down to approximately $8.3 million in April 2013." SCOOP Results Continental has approximately 232,000 net acres of leasehold in the SCOOP play, which stretches from Grady County to the southeast to Love County. In first quarter 2013, SCOOP net production averaged approximately 14,200 Boe per day, an increase of 100% sequentially and 462% above first quarter 2012. The recent growth was driven by impressive initial production rates and increased activity in the play, which included nine net (15 gross) additional operated and non-operated wells in the play during the first quarter 2013. In the condensate window, wells completed during first quarter 2013 averaged initial one-day tests of 1,050 Boe per day, which included 24% oil. The company is currently operating nine rigs in the play with plans to increase to 12. Select Continental-operated wells completed in the condensate window in first quarter 2013 include: oColbert 1-32H well produced 1,769 Boe per day (30% oil) in its initial one-day test period; and oKnox 1-1H well produced 1,151 Boe per day (26% oil) in its initial one-day test period. The Company plans to complete 55 net (115 gross) wells in the SCOOP play in 2013, including both operated and non-operated wells. Richard E. Muncrief, Continental's Senior Vice President of Operations, stated, "We are extremely excited about the doubling of our SCOOP production in one quarter. It is a huge credit to our teams, who have ramped up to nine rigs in a short period of time. We remain focused on delivering production targets, but also reducing cycle times and well costs, which is essential in order to compete for capital with our highly profitable Bakken activity." Conference Call Information Continental Resources plans to host a conference call to discuss first quarter 2013 results on Thursday, May, 9, 2013 at 10 a.m. ET (9 a.m. CT). Those wishing to listen to the conference call may do so via the Company's web site at www.CLR.com or by phone: Time and date: 10 a.m. ET, Thursday, May 9, 2013 Dial in: 888 680 0892 Intl. dial in: 617 213 4858 Pass code: 62640885 A replay of the call will be available for 30 days on the Company's web site or by dialing: Replay number: 888 286 8010 Intl. replay 617 801 6888 Pass code: 82241170 Callers who wish to pre-register for the call may go to: https://www.theconferencingservice.com/prereg/key.process?key=PL6YUULQB Upcoming Company Presentations Continental management is currently scheduled to present at the following investment conferences. Presentation materials will be available on the Company's website, www.CLR.com,the day of the event. May 13 FBR Energy & Industrials Conference, Boston; May 14 Bank of America Merrill Lynch Global Energy and Power Leveraged Finance Conference, New York City; May 16 Barrington Research Industrial & Business Services Conference, Chicago; May 21 UBS Oil and Gas Conference, Austin; June 11 Williams Financial Group First Annual Energy Conference, Dallas; and June 25 Global Hunter Securities 100 Energy Conference, Chicago. The Company's presentations at the conferences on May 21 and June 25 will be available via webcast. Instructions regarding how to access such webcasts will be available on the Company's web site at www.CLR.com on or prior to the day of the presentations. Such webcasts will be available for 30 days on the Company's web site. About Continental Resources Continental Resources, Inc. (NYSE: CLR), based in Oklahoma City, is focused on the exploration and production of onshore oil-prone plays and is a Top 10 independent oil producer in the United States. The Company has a long and successful history of developing its industry-leading leasehold and production in the nation's premier oil play, the Bakken of North Dakota and Montana, as well as significant positions in Oklahoma in its recently discovered SCOOP play and the Northwest Cana play. In 2013, the Company will celebrate 46 years of operation. Further information can be found at 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 March 31, 2013 2012 Revenues: In thousands, except per share data Crude oil and natural gas sales $ 783,517 $ 552,258 Loss on derivative instruments, net (84,831) (169,057) Crude oil and natural gas service 11,543 11,899 operations Total revenues 710,229 395,100 Operating costs and expenses: Production expenses 61,803 40,075 Production taxes and other expenses 72,429 50,740 Exploration expenses 9,814 4,151 Crude oil and natural gas service 8,597 9,842 operations Depreciation, depletion, amortization and 213,678 149,455 accretion Property impairments 40,081 29,907 General and administrative expenses 33,817 24,966 Gain on sale of assets, net (136) (49,627) Total operating costs and expenses 440,083 259,509 Income from operations 270,146 135,591 Other income (expense): Interest expense (47,475) (24,278) Other 546 781 (46,929) (23,497) Income before income taxes 223,217 112,094 Provision for income taxes 82,590 43,000 Net income $ 140,627 $ 69,094 Basic net income per share $ 0.76 $ 0.38 Diluted net income per share $ 0.76 $ 0.38 Continental Resources, Inc. Unaudited Condensed Consolidated Balance Sheets March 31, December 31, 2013 2012 Assets In thousands Current assets $ 1,080,592 $ 946,783 Net property and equipment 8,764,624 8,105,269 Other noncurrent assets 86,960 87,957 Total assets $ 9,932,176 $ 9,140,009 Liabilities and shareholders' equity Current liabilities $ 1,217,058 $ 1,125,865 Long-term debt 3,976,801 3,537,771 Other noncurrent liabilities 1,426,237 1,312,674 Total shareholders' equity 3,312,080 3,163,699 Total liabilities and shareholders' equity $ 9,932,176 $ 9,140,009 Continental Resources, Inc. Unaudited Condensed Consolidated Statements of Cash Flows Three months ended March 31, 2013 2012 In thousands Net income $ 140,627 $ 69,094 Adjustments to reconcile net income to net cash provided by operating activities: Non-cash expenses 428,913 306,966 Changes in assets and liabilities (111,429) (11,116) Net cash provided by operating activities 458,111 364,944 Net cash used in investing activities (873,153) (995,115) Net cash provided by financing activities 437,859 619,310 Net change in cash and cash equivalents 22,817 (10,861) Cash and cash equivalents at beginning of period 35,729 53,544 Cash and cash equivalents at end of period $ 58,546 $ 42,683 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. 1Q 2013 4Q 2012 1Q 2012 in thousands Net income $ 140,627 $ 220,511 $ 69,094 Interest expense 47,475 45,534 24,278 Provision for income taxes 82,590 99,992 43,000 Depreciation, depletion, amortization and 213,678 192,271 149,455 accretion Property impairments 40,081 29,121 29,907 Exploration expenses 9,814 5,755 4,151 Impact from derivative instruments: Total (gain) loss on derivatives, net 84,831 (9,639) 169,057 Total realized gain (loss) (cash flow) on (6,810) 2,655 (39,925) derivatives, net Non-cash (gain) loss on derivatives, net 78,021 (6,984) 129,132 Non-cash equity compensation 9,242 8,252 5,515 EBITDAX $ 621,528 $ 594,452 $ 454,532 The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented. 1Q 2013 1Q 2012 in thousands Net cash provided by operating activities $ 458,111 $ 364,944 Current income tax provision - 2,150 Interest expense 47,475 24,278 Exploration expenses, excluding dry hole costs 7,553 4,063 Gain on sale of assets, net 136 49,627 Other, net (3,176) (1,646) Changes in assets and liabilities 111,429 11,116 EBITDAX $ 621,528 $ 454,532 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. 1Q 2013 4Q 2012 1Q 2012 In thousands, After-Tax Diluted After-Tax Diluted After-Tax Diluted except per share $ EPS $ EPS $ EPS data Net income (GAAP) $ 140,627 $ $ 220,511 $ $ 69,094 $ 0.76 1.19 0.38 Adjustments, net of tax: Non-cash (gain) loss on 49,153 0.27 (4,331) (0.02) 79,933 0.44 derivatives, net Property 25,251 0.14 18,054 0.10 18,512 0.10 impairments Gain on sale of (86) - (42,723) (0.23) (30,719) (0.17) assets, net Corporate relocation 441 - 290 - 1,080 0.01 expenses Adjusted net $ $ $ income $ 215,386 1.17 $ 191,801 1.04 $ 137,900 0.76 (Non-GAAP) Weighted average diluted shares 184,656 184,603 180,283 outstanding Adjusted diluted $ $ $ net income per 1.17 1.04 0.76 share (Non-GAAP) Continental Resources, Inc. 2013 Guidance Outlook As of May 8, 2013 Production growth 35% to 40% Capital expenditures ^(1) $3.6 billion Price differentials: WTI crude oil (per barrel of oil) ($5.00) to ($7.00) Henry Hub natural gas (per Mcf) +$1.00 to +$1.50 Operating expenses: Production expense per Boe $5.20 to $5.60 Production tax (% of oil and gas revenues) 8% to 9% DD&A per Boe $19.00 to $21.00 G&A expense per Boe $2.20 to $2.70 Non-cash equity compensation per Boe $0.70 to $0.90 Income tax rate 37% Deferred taxes 90% to 95% (1) Excludes acquisition capital expenditures. SOURCE Continental Resources Website: http://www.CLR.com
Continental Resources Reports First Quarter 2013 Results
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