Continental Resources Reports Fourth Quarter 2013 And Full-Year Results Fourth Quarter Adjusted Net Income Totals $228.1 Million, or $1.23 per Diluted Share Fourth Quarter EBITDAX of $712 Million Brings Full-Year 2013 EBITDAX to Record $2.84 Billion Strong Early Performance of Hawkinson Density Pilot Wells 2014 Production on Track for 26% to 32% Growth in 2014 PR Newswire OKLAHOMA CITY, Feb. 26, 2014 OKLAHOMA CITY, Feb. 26, 2014 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced fourth quarter and full-year 2013 operating and financial results. Net income for the quarter ended December 31, 2013 was $132.8 million, or $0.72 per diluted share, compared with net income of $220.5 million, or $1.19 per diluted share, for the fourth quarter of 2012. Excluding items typically excluded from published analyst estimates, adjusted net income for the fourth quarter of 2013 was $228.1 million, or $1.23 per diluted share, a 19% increase over adjusted net income of $191.8 million, or $1.04 per diluted share, for the fourth quarter of 2012. (Logo: http://photos.prnewswire.com/prnh/20120327/DA76602LOGO) Net income for full-year 2013 was $764.2 million, or $4.13 per diluted share, compared with net income of $739.4 million, or $4.07 per diluted share, for full-year 2012. Excluding items typically excluded from published analyst estimates, adjusted net income for full-year 2013 was $986.1 million, or $5.33 per diluted share, a 61% increase over adjusted net income of $611.9 million, or $3.36 per diluted share, for full-year 2012. EBITDAX for the fourth quarter of 2013 was $712 million, a 20% increase over EBITDAX of $595 million for the fourth quarter of 2012. Full-year 2013 EBITDAX was a record $2.84 billion, a 45% increase over EBITDAX of $1.96 billion for full-year 2012. Definitions and reconciliations of adjusted net income, adjusted earnings per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures can be found in the supporting tables at the conclusion of this press release. "Our teams performed at an exceptional level in 2013, achieving our key growth targets for the initial year in our five-year plan to triple production and proved reserves," said Harold G. Hamm, Chairman and Chief Executive Officer. "The foundation of our plan is an unmatched inventory of oil and liquid-rich assets in the Bakken play of North Dakota and Montana and in the South Central Oklahoma Oil Province, or SCOOP. Our goal is to deliver exceptional production growth and cash margins, while maintaining a strong, conservative balance sheet. Both S&P and Moody's upgraded the Company to investment grade in the second half of 2013, clear evidence we are generating growth while maintaining financial strength and discipline." Fourth quarter and full-year 2013 highlights included: oAchieved the Company's original 2013 production and capital expenditures targets; oRecord proved reserves of 1.08 billion barrels of oil equivalent ("Boe") as of December 31, 2013, a 38% increase over year-end 2012 and a compounded annual growth of 47% since year-end 2008; and oRecord fourth quarter 2013 production of 144,254 Boe per day, a 35% increase over the fourth quarter of 2012. Production Fourth quarter 2013 Company net production totaled 13.3 million Boe, or 144,254 Boe per day, a sequential increase of 2% from third quarter 2013 and 35% higher than fourth quarter 2012. Total net production included approximately 100,400 barrels of oil per day (70% of production) and approximately 263 million cubic feet of natural gas per day (30% of production). In the fourth quarter 2013, the Company sold its operated natural gas production prior to processing based upon pricing provisions in its natural gas contracts. The Company estimates 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 for fourth quarter 2013. The following table provides the Company's average daily production by region for the periods presented. 4Q 3Q 4Q Boe per day 2013 2013 2012 North Region: North Dakota Bakken 80,374 81,545 59,019 Montana Bakken 12,961 12,957 8,503 Red River Units 14,398 14,703 14,716 Other 812 408 967 South Region: SCOOP 23,754 20,070 7,123 NW Cana 6,696 6,985 9,716 Arkoma 2,769 3,004 3,225 Other 2,490 2,201 2,556 East Region - - 1,006 Total 144,254 141,873 106,831 Bakken Development Continental's Bakken production totaled 93,335 Boe per day in the fourth quarter of 2013, essentially flat compared to third quarter 2013 and an increase of 38% compared to fourth quarter 2012. Base production and growth, including operated and non-operated production, were adversely affected by winter weather conditions in the quarter, especially during December 2013. As a result, Continental currently has approximately 110 gross wells that have been drilled but are awaiting completion or infrastructure in the Bakken. This is approximately 35 gross wells above the Company's typical run rate level of activity. The Company has added additional third-party completion services in order to reduce the inventory and expedite initial production of recent drilled wells. The Company plans to complete approximately 287 net (870 gross) wells in the Bakken in 2014, including both operated and non-operated wells, and is subject to change. The Company operated 20 rigs in the play in fourth quarter 2013 and anticipates operating an average rig count of 22 throughout 2014. Continental's average operated well costs in the Bakken continue to trend lower. Fourth quarter 2013 operated Bakken well costs were approximately $8.0 million per well. The Company is targeting even lower well costs with a goal of $7.5 million per operated Bakken well by year-end 2014 for its typical completion design. As previously indicated, Continental plans to test several different completion design techniques on approximately 20% of its Bakken completions in 2014 to evaluate possible performance enhancements. Projected capital expenditures for the Northern region, which includes the Bakken and the Red River units, are approximately $2.9 billion for 2014. Bakken Density and Productivity Update: The Hawkinson Unit In North Dakota during October 2013, Continental successfully completed the first pilot density project at the Hawkinson unit in Dunn County. The 14 individual wells within the unit tested at a combined rate of 14,850 Boe per day, which included three existing producing wells. The project included four Middle Bakken, three TF1 (Three Forks 1), four TF2 and three TF3 wells spaced 1,320 feet apart in the same zone and offset 660 feet in the adjacent zones. Based on the first 120 days of production, 12 of the 14 wells on the Hawkinson unit are performing very well and average production is trending 50% above the Company's 603,000 Boe estimated ultimate recovery ("EUR") model for a typical North Dakota Bakken well. The two exception wells are in the TF3 zone and were recently put on pump. Theyare producing on trend just below the 603,000 Boe EUR model, but improving. Given the limited amount of production history, these trends could change over time. Continental has an approximate 55% working interest in the Hawkinson Unit. W. F. "Rick" Bott, Continental's President and Chief Operating Officer, commented, "The Hawkinson project has been a huge success and the culmination of efforts across the entire company – geology, micro-seismic, drilling, completions,surface logistics and marketing, to name a few. This is a landmark event for our Company and the industry – unique production from four different producing intervals and spaced 1,320 feet apart. This first test validates our vision for full-field development of the Bakken and the vast resource potential across our acreage position." In addition to the Hawkinson project, Continental has three other density pilot tests in North Dakota which the Company began drilling in 2013, including wells in the Middle Bakken, TF1, TF2 and TF3. The Tangsrud project in Divide County is a 1,320 feet inter-well spacing test including 12 new wells. Ten of the wells are currently beginning the initial flowback stage and the two remaining wells should commence production by early March. The Rollefstad project in eastern McKenzie County involves 11 new wells drilled with 1,320 feet same zone inter-well spacing, similar to the Hawkinson and Tangsrud. Completion activities are in progress at the Rollefstad unit, including well clean out and tubing installation and full production is expected in late March. The Wahpeton density pilot in western McKenzie County involves 13 new wells configured in four zones at increased density spacing of 660 feet inter-well spacing. Full unit production startup is expected in early May. The original completion schedule for the Tangsrud, Rollefstad and Wahpeton units was delayed due to challenging weather conditions. During 2014, Continental has begun drilling three additional density pilots to test 660 feet inter-well spacing at the Lawrence, Mack and Hartman units, which include 18 new wells and six existing producers. Antelope "Ears Back" Program Update Continental announced in November 2013 the Company would begin its first full-field development in the Bakken, including the deeper Three Forks benches, in McKenzie and Mountrail counties in the Antelope area and plans to drill between 350 to 400 gross wells over the next five years. The area was selected due to the Company's large operated footprint and historical results that are among the Company's highest rates of return. Continental currently has three rigs running in the Antelope area and has 18 wells in various stages of drilling or completion. Growth in SCOOP Continues Continental continues to deliver excellent, repeatable results from its drilling activity in the South Central Oklahoma Oil Province ("SCOOP"). The play, discovered by Continental and announced in October 2012, currently extends approximately 120 miles across several counties in Oklahoma and contains oil and condensate-rich fairways as delineated by approximately 450 gross industry wells. Continental currently operates or has a working interest in approximately 155 wells across its approximately 400,000 net acres of leasehold in the play. In fourth quarter 2013, SCOOP net production averaged approximately 23,750 Boe per day, an increase of 18% sequentially and 233% above fourth quarter 2012. The recent growth was driven by the addition of 12 net (23 gross) operated and non-operated wells in the play during the fourth quarter 2013. In SCOOP, Continental's primary focus continues to be exploration, appraisal and drilling to hold acreage (HBP), with an increasing shift to 2-mile lateral wells. The Company operated an average of 14 rigs during fourth quarter 2013 and plans to average 18 operated rigs in the play in 2014, with 40% of the activity on 2-mile lateral wells. Well costs in the play are targeted by year-end 2014 to be approximately $8.7 million for a standard 1-mile lateral across the play within the exploration program and approximately $13.5 million for a 2-mile lateral. Continental plans a number of spacing tests and one density pilot in 2014. Continental projects capital expenditures of approximately $1.1 billion in the Southern region in 2014, which includes SCOOP and other areas. In fourth quarter 2013, average initial one-day test rates from operated and non-operated wells within the oil and condensate fairways of SCOOP were approximately 1,300 boe per day. Financial Update and Guidance Continental's average realized sales price excluding the effects of derivative positions was $84.47 per barrel of oil and $5.49 per thousand cubic feet of natural gas ("Mcf"), or $68.80 per Boe for fourth quarter 2013. Settlements of matured commodity derivative positions generated a $1.05 loss per barrel of oil resulting in a net loss on matured derivatives of $9.6 million, or $0.73 per Boe for the fourth quarter 2013. Based on realizations without the effect of derivatives, the Company's fourth quarter 2013 oil differential was $13.05 per barrel below the NYMEX daily average for the period. The realized natural gas price differential for fourth quarter 2013 was a positive $1.88 per Mcf. Full-year 2013 realized differential without the effect of derivatives was a negative $8.23 per barrel of oil and a positive $1.59 per Mcf as compared to the NYMEX daily averages for the year. Full-year 2013 oil differential was above the Company's guidance estimate due to fourth quarter price volatility, while natural gas differential was better than guidance. Production expense per Boe was $6.03 for fourth quarter 2013, an increase from third quarter 2013 due to increased costs and lower volumes due to weather conditions. Other select operating costs and expenses for fourth quarter 2013 included production taxes of 8.1% of oil and natural gas sales; DD&A of $20.40 per Boe; and G&A (cash and non-cash, excluding relocation expenses) of $3.06 per Boe. On a full-year basis, these expense categories were within the Company's full-year guidance. As of December 31, 2013, Continental's balance sheet included approximately $28 million in cash and cash equivalents and $275 million of borrowings against the Company's $1.5 billion credit facility. During fourth quarter 2013, Moody's Investor Services upgraded the Company's senior unsecured rating to investment grade status of Baa3, up from Ba2. Non-acquisition capital expenditures for fourth quarter 2013 totaled approximately $868 million, including $766 million in exploration and development drilling, $62 million in leasehold and seismic and $40 million in workovers, recompletions and other. Acquisition capital expenditures totaled approximately $71 million for fourth quarter 2013. Full-year 2013 non-acquisition capital expenditures totaled approximately $3.574 billion, just below guidance. Acquisition spending totaled approximately $268 million for the year. Continental's 2014 guidance remains unchanged as originally disclosed on September 10, 2013, which includes organic production growth of 26% to 32% with a capital budget of $4.05 billion. A table with the Company's full 2014 guidance, which includes differentials and select cost elements, can be found at the conclusion of this release. The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes. Three months ended December Year ended December 31, 31, 2013 2012 2013 2012 Average daily production: Crude oil (Bbl per day) 100,443 76,449 95,859 68,497 Natural gas (Mcf per 262,866 182,289 240,355 174,521 day) Crude oil equivalents 144,254 106,831 135,919 97,583 (Boe per day) Average sales prices, excluding effect from derivatives: Crude oil ($/Bbl) $84.47 $84.99 $89.93 $84.59 Natural gas ($/Mcf) $5.49 $4.82 $5.25 $4.20 Crude oil equivalents $68.80 $68.89 $72.71 $66.83 ($/Boe) Production expenses $6.03 $5.90 $5.69 $5.49 ($/Boe) Production taxes (% of 8.1% 8.3% 8.2% 8.2% oil and gas revenues) DD&A ($/Boe) $20.40 $19.76 $19.47 $19.44 General and administrative expenses $2.27 $2.70 $2.07 $2.38 ($/Boe) ^(1) Non-cash equity $0.79 $0.85 $0.80 $0.82 compensation ($/Boe) Net income (in $132,824 $220,511 $764,219 $739,385 thousands) Diluted net income per $0.72 $1.19 $4.13 $4.07 share Adjusted net income (in $228,132 $191,801 $986,125 $611,870 thousands) ^(2) Adjusted diluted net $1.23 $1.04 $5.33 $3.36 income per share ^(2) EBITDAX (in thousands) $712,300 $594,452 $2,839,510 $1,963,123 ^(2) General and administrative expenses ($/Boe) exclude non-recurring corporate relocation expenses of $0.2 million ($0.01 per Boe) for the three months ended December 31, 2013 and $0.5 million ($0.05 per Boe) for (1) the three months ended December 31, 2012. For the year ended December 31, 2013, general and administrative expenses exclude non-recurring corporate relocation expenses of $1.6 million ($0.04 per Boe) and $7.8 million ($0.22 per Boe) for the same period in 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 fourth quarter and full-year 2013 results on Thursday, February 27, 2014 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, February 27, 2014 Dial in: 800 708 4539 Intl. dial in: 847 619 6396 Pass code: 36590660 A replay of the call will be available for 30 days on the Company's website or by dialing: Replay number: 888 843 7419 Intl. replay 630 652 3042 Pass code: 36590660 Continental plans to publish a fourth quarter and full-year 2013 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on February 27, 2014. Upcoming Conferences Members of Continental's management team will be participating in the following upcoming investment conferences: March 3, 2014 Raymond James Institutional Investors Conference: Orlando March 5, 2014 Barclays Investment Grade Energy & Pipeline Conference: New York March 26, 2014 Howard Weil 42^nd Annual Energy Conference: New Orleans The Company's presentation at the Raymond James conference will be available via webcast and a replay 30 days thereafter. Instructions regarding how to access the live and replay webcast for the Raymond James presentation and presentation materials for all conferences mentioned above 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 2014, the company will celebrate 47 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, 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 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 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: John Kilgallon Kristin Miskovsky Vice President, Investor Relations Vice President, Public Relations 405-234-9330 405-234-9480 John.Kilgallon@CLR.com Kristin.Miskovsky@CLR.com Warren Henry Vice President, Research and Policy 405-234-9127 Waren.Henry@CLR.com Continental Resources, Inc. Consolidated Statements of Income (Unaudited) Three months ended December Year ended December 31, 31, 2013 2012 2013 2012 Revenues: In thousands, except per share data Crude oil and $ 912,286 $ 670,438 $ 3,606,774 $ 2,379,433 natural gas sales Gain (loss) on derivative (102,202) 9,639 (191,751) 154,016 instruments, net Crude oil and natural gas service 10,250 8,895 40,127 39,071 operations Total revenues 820,334 688,972 3,455,150 2,572,520 Operating costs and expenses: Production expenses 79,892 57,399 282,197 195,440 Production taxes and 84,183 65,558 332,130 228,438 other expenses Exploration expenses 5,809 5,755 34,947 23,507 Crude oil and natural gas service 7,097 7,525 29,665 32,248 operations Depreciation, depletion, 270,456 192,271 965,645 692,118 amortization and accretion Property impairments 58,548 29,121 220,508 122,274 General and administrative 40,619 35,031 144,379 121,735 expenses Gain (loss) on sale 24 (68,908) (88) (136,047) of assets, net Total operating 546,628 323,752 2,009,383 1,279,713 costs and expenses Income from 273,706 365,220 1,445,767 1,292,807 operations Other income (expense): Interest expense (63,666) (45,534) (235,275) (140,708) Other 792 817 2,557 3,097 (62,874) (44,717) (232,718) (137,611) Income before income 210,832 320,503 1,213,049 1,155,196 taxes Provision for income 78,008 99,992 448,830 415,811 taxes Net income $ 132,824 $ 220,511 $ 764,219 $ 739,385 Basic net income per $ 0.72 $ 1.20 $ 4.15 $ 4.08 share Diluted net income $ 0.72 $ 1.19 $ 4.13 $ 4.07 per share Continental Resources, Inc. Consolidated Balance Sheets December 31, December 31, 2013 2012 Assets In thousands Current assets $ 1,147,266 $ 946,783 Net property and equipment ^(1) 10,721,272 8,105,269 Other noncurrent assets 72,644 87,957 Total assets $ 11,941,182 $ 9,140,009 Liabilities and shareholders' equity Current liabilities $ 1,473,156 $ 1,125,865 Long-term debt 4,713,821 3,537,771 Other noncurrent liabilities 1,801,087 1,312,674 Total shareholders' equity 3,953,118 3,163,699 Total liabilities and shareholders' equity $ 11,941,182 $ 9,140,009 Balance is net of accumulated depreciation, depletion and amortization of (1) $3.12 billion and $2.12 billion as of December 31, 2013 and 2012, respectively. Continental Resources, Inc. Consolidated Statements of Cash Flows (Unaudited) Three months ended December Year ended December 31, 31, In thousands 2013 2012 2013 2012 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 512,189 223,804 1,809,951 905,695 Changes in assets (60,171) 39,853 (10,875) (13,015) and liabilities Net cash provided by operating 584,842 484,168 2,563,295 1,632,065 activities Net cash used in investing (911,623) (1,312,243) (3,711,011) (3,903,370) activities Net cash provided by financing 263,756 604,359 1,140,469 2,253,490 activities Net change in cash and cash (63,025) (223,716) (7,247) (17,815) equivalents Cash and cash equivalents at 91,507 259,445 35,729 53,544 beginning of period Cash and cash equivalents at end $ 28,482 $ 35,729 $ 28,482 $ 35,729 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. Three months ended December Year ended December 31, 31, In thousands 2013 2012 2013 2012 Net income $ 132,824 $ 220,511 $ 764,219 $ 739,385 Interest expense 63,666 45,534 235,275 140,708 Provision for income 78,008 99,992 448,830 415,811 taxes Depreciation, depletion, amortization 270,456 192,271 965,645 692,118 and accretion Property impairments 58,548 29,121 220,508 122,274 Exploration expenses 5,809 5,755 34,947 23,507 Impact from derivative instruments: Total (gain) loss on 102,202 (9,639) 191,751 (154,016) derivatives, net Total cash (paid) received on (9,644) 2,655 (61,555) (45,721) derivatives, net Non-cash (gain) loss on 92,558 (6,984) 130,196 (199,737) derivatives, net Non-cash equity 10,431 8,252 39,890 29,057 compensation EBITDAX $ 712,300 $ 594,452 $ 2,839,510 $ 1,963,123 The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented. Three months ended December 31, Year ended December 31, In thousands 2013 2012 2013 2012 Net cash provided by operating $ 584,842 $ 484,168 $ 2,563,295 $ 1,632,065 activities Current income tax (4,014) 18,241 6,209 10,517 provision (benefit) Interest expense 63,666 45,534 235,275 140,708 Exploration expenses, excluding 5,639 5,307 25,597 22,740 dry hole costs Gain (loss) on sale (24) 68,908 88 136,047 of assets, net Excess tax benefit from stock-based - 15,618 - 15,618 compensation Other, net 2,020 (3,471) (1,829) (7,587) Changes in assets 60,171 (39,853) 10,875 13,015 and liabilities EBITDAX $ 712,300 $ 594,452 $ 2,839,510 $ 1,963,123 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. Three Months Ended December 31, 2013 2012 In thousands, except per After-Tax $ Diluted EPS After-Tax $ Diluted share data EPS Net income (GAAP) $ 132,824 $ $ 220,511 $ 0.72 1.19 Adjustments, net of tax: Non-cash (gain) loss on 58,312 0.31 (4,331) (0.02) derivatives, net Property impairments 36,885 0.20 18,054 0.10 (Gain) loss on sale of 15 - (42,723) (0.23) assets, net Corporate relocation 96 - 290 - expenses Adjusted net income $ 228,132 $ $ 191,801 $ (Non-GAAP) 1.23 1.04 Weighted average diluted 185,007 184,603 shares outstanding Adjusted diluted net $ $ income per share 1.23 1.04 (Non-GAAP) Year Ended December 31, 2013 2012 In thousands, except per After-Tax $ Diluted EPS After-Tax $ Diluted share data EPS Net income (GAAP) $ 764,219 $ $ 739,385 $ 4.13 4.07 Adjustments, net of tax: Non-cash (gain) loss on 82,023 0.44 (123,838) (0.68) derivatives, net Property impairments 138,920 0.75 75,810 0.41 (Gain) loss on sale of (55) - (84,349) (0.46) assets, net Corporate relocation 1,018 0.01 4,862 0.02 expenses Adjusted net income $ 986,125 $ $ 611,870 $ (Non-GAAP) 5.33 3.36 Weighted average diluted 184,849 181,846 shares outstanding Adjusted diluted net $ $ income per share 5.33 3.36 (Non-GAAP) Continental Resources, Inc. 2014 Guidance Outlook 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, 2013 SOURCE Continental Resources Website: http://www.clr.com
Continental Resources Reports Fourth Quarter 2013 And Full-Year Results
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