CLR FY2013 Q2
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________
FORM 10-Q
_______________________________
(Mark One)
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x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2013
or
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¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-32886
_______________________________
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
_______________________________
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Oklahoma | | 73-0767549 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
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20 N. Broadway, Oklahoma City, Oklahoma | | 73102 |
(Address of principal executive offices) | | (Zip Code) |
(405) 234-9000
(Registrant’s telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year, if changed since last report)
_______________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer | | x | | Accelerated filer | | ¨ |
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Non-accelerated filer | | ¨ (Do not check if a smaller reporting company) | | Smaller reporting company | | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
185,638,546 shares of our $0.01 par value common stock were outstanding on August 1, 2013.
Table of Contents
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Item 1. | | |
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Item 2. | | |
Item 3. | | |
Item 4. | | |
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Item 1. | | |
Item 1A. | | |
Item 2. | | |
Item 3. | | |
Item 4. | | |
Item 5. | | |
Item 6. | | |
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When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.
Glossary of Crude Oil and Natural Gas Terms
The terms defined in this section may be used throughout this report:
“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.
“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
“conventional play” An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.
“DD&A” Depreciation, depletion, amortization and accretion.
“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.
“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry gas” Refers to natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also may refer to gas that has been processed or treated to remove all natural gas liquids.
“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.
“enhanced recovery” The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.
“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“formation” A layer of rock which has distinct characteristics that differs from nearby rock.
“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
“hydraulic fracturing” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production.
“injection well” A well into which liquids or gases are injected in order to “push” additional crude oil or natural gas out of underground reservoirs and into the wellbores of producing wells. Typically considered an enhanced recovery process.
“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.
“MBoe” One thousand Boe.
“Mcf” One thousand cubic feet of natural gas.
“MMBoe” One million Boe.
“MMBtu” One million British thermal units.
“MMcf” One million cubic feet of natural gas.
“net acres” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has a 50% interest in 100 acres owns 50 net acres.
“NYMEX” The New York Mercantile Exchange.
“play” A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.
“productive well” A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.
“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
“proved developed reserves” Reserves expected to be recovered through existing wells with existing equipment and operating methods.
“proved undeveloped reserves” or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“resource play” Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and multi-stage fracturing technologies.
“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
“SCOOP” Refers to the South Central Oklahoma Oil Province, a term we use to describe an emerging area of crude oil and liquids-rich natural gas properties located in the Anadarko basin of south central Oklahoma.
“unconventional play” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.
“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report 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 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, included in this report are forward-looking statements. When used in this report, 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, you should keep in mind the risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors included in this report, our Annual Report on Form 10-K for the year ended December 31, 2012, registration statements filed from time to time with the SEC, and other announcements we make from time to time.
Without limiting the generality of the foregoing, certain statements incorporated by reference, if any, or included in this report constitute forward-looking statements.
Forward-looking statements may include statements about:
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• | crude oil, natural gas liquids, and natural gas prices and differentials; |
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• | the timing and amount of future production of crude oil and natural gas and flaring activities; |
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• | the amount, nature and timing of capital expenditures; |
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• | estimated revenues, expenses and results of operations; |
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• | drilling and completing of wells; |
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• | marketing of crude oil and natural gas; |
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• | transportation of crude oil, natural gas liquids, and natural gas to markets; |
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• | exploitation or property acquisitions and dispositions; |
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• | costs of exploiting and developing our properties and conducting other operations; |
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• | general economic conditions; |
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• | our liquidity and access to capital; |
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• | the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes; |
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• | our future operating results; |
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• | plans, objectives, expectations and intentions contained in this report that are not historical, including, without limitation, statements regarding our future growth plans; |
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• | our commodity hedging arrangements; and |
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• | the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us. |
We caution you 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 our 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, completion 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 II, Item 1A. Risk Factors in this report, our Annual Report on Form 10-K for the year ended December 31, 2012, registration statements filed from time to time with the SEC, and other announcements we make 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 report occur, or should underlying assumptions prove incorrect, our 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 we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this report.
PART I. Financial Information
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ITEM 1. | Financial Statements |
Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
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| | June 30, 2013 | | December 31, 2012 |
In thousands, except par values and share data | | (Unaudited) | | |
Assets | | | | |
Current assets: | | | | |
Cash and cash equivalents | | $ | 220,413 |
| | $ | 35,729 |
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Receivables: | | | | |
Crude oil and natural gas sales | | 584,392 |
| | 468,650 |
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Affiliated parties | | 15,902 |
| | 12,410 |
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Joint interest and other, net | | 339,388 |
| | 356,111 |
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Derivative assets | | 76,478 |
| | 18,389 |
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Inventories | | 42,085 |
| | 46,743 |
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Deferred and prepaid taxes | | 6,425 |
| | 365 |
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Prepaid expenses and other | | 8,547 |
| | 8,386 |
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Total current assets | | 1,293,630 |
| | 946,783 |
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Net property and equipment, based on successful efforts method of accounting | | 9,440,216 |
| | 8,105,269 |
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Net debt issuance costs and other | | 74,570 |
| | 55,726 |
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Noncurrent derivative assets | | 91,566 |
| | 32,231 |
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Total assets | | $ | 10,899,982 |
| | $ | 9,140,009 |
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Liabilities and shareholders’ equity | | | | |
Current liabilities: | | | | |
Accounts payable trade | | $ | 769,249 |
| | $ | 687,310 |
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Revenues and royalties payable | | 276,446 |
| | 261,856 |
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Payables to affiliated parties | | 5,476 |
| | 6,069 |
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Accrued liabilities and other | | 195,501 |
| | 153,454 |
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Derivative liabilities | | 6,809 |
| | 12,999 |
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Current portion of asset retirement obligations | | 1,964 |
| | 2,227 |
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Current portion of long-term debt | | 1,981 |
| | 1,950 |
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Total current liabilities | | 1,257,426 |
| | 1,125,865 |
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Long-term debt, net of current portion | | 4,440,820 |
| | 3,537,771 |
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Other noncurrent liabilities: | | | | |
Deferred income tax liabilities | | 1,510,511 |
| | 1,262,576 |
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Asset retirement obligations, net of current portion | | 45,568 |
| | 44,944 |
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Noncurrent derivative liabilities | | — |
| | 2,173 |
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Other noncurrent liabilities | | 2,317 |
| | 2,981 |
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Total other noncurrent liabilities | | 1,558,396 |
| | 1,312,674 |
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Commitments and contingencies (Note 7) | |
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Shareholders’ equity: | | | | |
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding | | — |
| | — |
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Common stock, $0.01 par value; 500,000,000 shares authorized; 185,642,832 shares issued and outstanding at June 30, 2013; 185,604,681 shares issued and outstanding at December 31, 2012 | | 1,856 |
| | 1,856 |
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Additional paid-in capital | | 1,242,579 |
| | 1,226,835 |
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Retained earnings | | 2,398,905 |
| | 1,935,008 |
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Total shareholders’ equity | | 3,643,340 |
| | 3,163,699 |
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Total liabilities and shareholders’ equity | | $ | 10,899,982 |
| | $ | 9,140,009 |
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The accompanying notes are an integral part of these condensed consolidated financial statements.
1
Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Income
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| | Three months ended June 30, | | Six months ended June 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
In thousands, except per share data | | |
Revenues | | | | | | | | |
Crude oil and natural gas sales | | $ | 864,538 |
| | $ | 511,192 |
| | $ | 1,627,170 |
| | $ | 1,046,504 |
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Crude oil and natural gas sales to affiliates | | 27,649 |
| | 12,201 |
| | 48,534 |
| | 29,147 |
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Gain on derivative instruments, net | | 199,056 |
| | 471,728 |
| | 114,225 |
| | 302,671 |
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Crude oil and natural gas service operations | | 9,509 |
| | 9,598 |
| | 21,052 |
| | 21,497 |
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Total revenues | | 1,100,752 |
| | 1,004,719 |
| | 1,810,981 |
| | 1,399,819 |
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Operating costs and expenses | | | | | | | | |
Production expenses | | 73,143 |
| | 43,479 |
| | 134,460 |
| | 83,495 |
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Production and other expenses to affiliates | | 1,495 |
| | 1,427 |
| | 3,152 |
| | 2,496 |
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Production taxes and other expenses | | 81,050 |
| | 48,077 |
| | 152,308 |
| | 97,807 |
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Exploration expenses | | 11,151 |
| | 8,702 |
| | 20,965 |
| | 12,853 |
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Crude oil and natural gas service operations | | 7,317 |
| | 7,255 |
| | 15,914 |
| | 17,097 |
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Depreciation, depletion, amortization and accretion | | 236,790 |
| | 161,018 |
| | 450,468 |
| | 310,473 |
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Property impairments | | 79,712 |
| | 35,871 |
| | 119,793 |
| | 65,778 |
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General and administrative expenses | | 35,873 |
| | 29,813 |
| | 69,690 |
| | 54,779 |
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(Gain) loss on sale of assets, net | | 349 |
| | (17,397 | ) | | 213 |
| | (67,024 | ) |
Total operating costs and expenses | | 526,880 |
| | 318,245 |
| | 966,963 |
| | 577,754 |
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Income from operations | | 573,872 |
| | 686,474 |
| | 844,018 |
| | 822,065 |
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Other income (expense): | | | | | | | | |
Interest expense | | (61,378 | ) | | (31,691 | ) | | (108,853 | ) | | (55,969 | ) |
Other | | 634 |
| | 789 |
| | 1,180 |
| | 1,570 |
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| | (60,744 | ) | | (30,902 | ) | | (107,673 | ) | | (54,399 | ) |
Income before income taxes | | 513,128 |
| | 655,572 |
| | 736,345 |
| | 767,666 |
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Provision for income taxes | | 189,858 |
| | 249,888 |
| | 272,448 |
| | 292,888 |
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Net income | | $ | 323,270 |
| | $ | 405,684 |
| | $ | 463,897 |
| | $ | 474,778 |
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Basic net income per share | | $ | 1.76 |
| | $ | 2.26 |
| | $ | 2.52 |
| | $ | 2.64 |
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Diluted net income per share | | $ | 1.75 |
| | $ | 2.25 |
| | $ | 2.51 |
| | $ | 2.63 |
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The accompanying notes are an integral part of these condensed consolidated financial statements.
2
Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Statements of Shareholders’ Equity
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| | Shares outstanding | | Common stock | | Additional paid-in capital | | Retained earnings | | Total shareholders’ equity |
In thousands, except share data | | |
Balance at December 31, 2012 | | 185,604,681 |
| | $ | 1,856 |
| | $ | 1,226,835 |
| | $ | 1,935,008 |
| | $ | 3,163,699 |
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Net income (unaudited) | | — |
| | — |
| | — |
| | 463,897 |
| | 463,897 |
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Stock-based compensation (unaudited) | | — |
| | — |
| | 19,003 |
| | — |
| | 19,003 |
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Restricted stock: | | | | | | | | | | |
Issued (unaudited) | | 129,850 |
| | 1 |
| | — |
| | — |
| | 1 |
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Repurchased and canceled (unaudited) | | (38,876 | ) | | — |
| | (3,259 | ) | | — |
| | (3,259 | ) |
Forfeited (unaudited) | | (52,823 | ) | | (1 | ) | | — |
| | — |
| | (1 | ) |
Balance at June 30, 2013 | | 185,642,832 |
| | $ | 1,856 |
| | $ | 1,242,579 |
| | $ | 2,398,905 |
| | $ | 3,643,340 |
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The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Cash Flows
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| | | | | | | | |
| | Six months ended June 30, |
In thousands | | 2013 | | 2012 |
Cash flows from operating activities | | |
Net income | | $ | 463,897 |
| | $ | 474,778 |
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Adjustments to reconcile net income to net cash provided by operating activities: | | | | |
Depreciation, depletion, amortization and accretion | | 448,639 |
| | 314,367 |
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Property impairments | | 119,793 |
| | 65,778 |
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Change in fair value of derivatives | | (125,787 | ) | | (349,652 | ) |
Stock-based compensation | | 18,998 |
| | 13,305 |
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Provision for deferred income taxes | | 266,618 |
| | 290,738 |
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Dry hole costs | | 8,063 |
| | 98 |
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(Gain) loss on sale of assets, net | | 213 |
| | (67,024 | ) |
Other, net | | 2,466 |
| | 2,275 |
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Changes in assets and liabilities: | | | | |
Accounts receivable | | (100,542 | ) | | 18,375 |
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Inventories | | 4,658 |
| | (10,212 | ) |
Prepaid expenses and other | | (6,526 | ) | | 2,952 |
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Accounts payable trade | | 21,678 |
| | (21,661 | ) |
Revenues and royalties payable | | 12,920 |
| | 4,477 |
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Accrued liabilities and other | | 16,018 |
| | 32,241 |
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Other noncurrent assets and liabilities | | 5,839 |
| | (5 | ) |
Net cash provided by operating activities | | 1,156,945 |
| | 770,830 |
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| | | | |
Cash flows from investing activities | | | | |
Exploration and development | | (1,823,215 | ) | | (1,778,808 | ) |
Purchase of producing crude oil and natural gas properties | | (9,311 | ) | | (63,263 | ) |
Purchase of other property and equipment | | (18,545 | ) | | (32,230 | ) |
Proceeds from sale of assets | | 894 |
| | 100,809 |
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Net cash used in investing activities | | (1,850,177 | ) | | (1,773,492 | ) |
| | | | |
Cash flows from financing activities | | | | |
Revolving credit facility borrowings | | 440,000 |
| | 1,239,000 |
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Repayment of revolving credit facility | | (1,035,000 | ) | | (1,060,000 | ) |
Proceeds from issuance of Senior Notes | | 1,479,375 |
| | 787,000 |
|
Proceeds from other debt | | — |
| | 22,000 |
|
Repayment of other debt | | (969 | ) | | (628 | ) |
Debt issuance costs | | (2,231 | ) | | (4,083 | ) |
Repurchase of equity grants | | (3,259 | ) | | (5,094 | ) |
Exercise of stock options | | — |
| | 60 |
|
Net cash provided by financing activities | | 877,916 |
| | 978,255 |
|
Net change in cash and cash equivalents | | 184,684 |
| | (24,407 | ) |
Cash and cash equivalents at beginning of period | | 35,729 |
| | 53,544 |
|
Cash and cash equivalents at end of period | | $ | 220,413 |
| | $ | 29,137 |
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The accompanying notes are an integral part of these condensed consolidated financial statements.
4
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Organization and Nature of Business
Description of the Company
Continental’s principal business is crude oil and natural gas exploration, development and production with properties in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi River including the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma Woodford plays in Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River.
The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 77% of the Company’s crude oil and natural gas production and approximately 87% of its crude oil and natural gas revenues for the six months ended June 30, 2013. The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the six months ended June 30, 2013, crude oil accounted for approximately 71% of the Company’s total production and approximately 88% of its crude oil and natural gas revenues.
Note 2. Basis of Presentation and Significant Accounting Policies
Basis of presentation
The condensed consolidated financial statements include the accounts of Continental and its wholly owned subsidiaries after all significant intercompany accounts and transactions have been eliminated upon consolidation.
This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Form 10-Q together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.
The condensed consolidated financial statements as of June 30, 2013 and for the three and six month periods ended June 30, 2013 and 2012 are unaudited. The condensed consolidated balance sheet as of December 31, 2012 was derived from the audited balance sheet included in the 2012 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited interim condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for the entire year.
Inventories
Inventories are stated at the lower of cost or market and consist of the following:
|
| | | | | | | | |
In thousands | | June 30, 2013 | | December 31, 2012 |
Tubular goods and equipment | | $ | 12,326 |
| | $ | 13,590 |
|
Crude oil | | 29,759 |
| | 33,153 |
|
Total | | $ | 42,085 |
| | $ | 46,743 |
|
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Crude oil inventories are valued at the lower of cost or market using the first-in, first-out inventory method. Crude oil inventories consist of the following volumes:
|
| | | | | | |
MBbls | | June 30, 2013 | | December 31, 2012 |
Crude oil line fill requirements | | 398 |
| | 391 |
|
Temporarily stored crude oil | | 97 |
| | 211 |
|
Total | | 495 |
| | 602 |
|
Earnings per share
Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards and stock options, which are calculated using the treasury stock method as if the awards and options were exercised. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share for the three and six months ended June 30, 2013 and 2012. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012. |
| | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
In thousands, except per share data | | |
Income (numerator): | | | | | | | | |
Net income - basic and diluted | | $ | 323,270 |
| | $ | 405,684 |
| | $ | 463,897 |
| | $ | 474,778 |
|
Weighted average shares (denominator): | | | | | | | | |
Weighted average shares - basic | | 184,039 |
| | 179,781 |
| | 184,019 |
| | 179,744 |
|
Non-vested restricted stock | | 700 |
| | 554 |
| | 685 |
| | 541 |
|
Stock options | | — |
| | — |
| | — |
| | 32 |
|
Weighted average shares - diluted | | 184,739 |
| | 180,335 |
| | 184,704 |
| | 180,317 |
|
Net income per share: | | | | | | | | |
Basic | | $ | 1.76 |
| | $ | 2.26 |
| | $ | 2.52 |
| | $ | 2.64 |
|
Diluted | | $ | 1.75 |
| | $ | 2.25 |
| | $ | 2.51 |
| | $ | 2.63 |
|
Adoption of new accounting standard
In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance Sheet (Topic 210)–Disclosures about Offsetting Assets and Liabilities. The new standard requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The disclosures are required for recognized financial instruments and derivative instruments that are subject to offsetting under current accounting literature or are subject to master netting arrangements irrespective of whether they are offset. The disclosure requirements became effective for periods beginning on or after January 1, 2013 and must be applied retrospectively to all periods presented on the balance sheet. The Company adopted the provisions of the new standard on January 1, 2013 and has included the required disclosures in Note 4. Derivative Instruments. Adoption of the new standard required additional footnote disclosures for the Company's derivative instruments and did not have an impact on its financial position, results of operations or cash flows.
Note 3. Supplemental Cash Flow Information
The following table discloses supplemental cash flow information about cash paid for interest and income taxes. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
|
| | | | | | | | |
| | Six months ended June 30, |
| | 2013 | | 2012 |
In thousands | | |
Supplemental cash flow information: | | | | |
Cash paid for interest | | $ | 88,856 |
| | $ | 38,567 |
|
Cash paid for income taxes | | 16,883 |
| | 754 |
|
Cash received for income tax refunds | | (173 | ) | | (72 | ) |
Non-cash investing activities: | | | | |
Increase in accrued capital expenditures | | 59,414 |
| | 43,850 |
|
Asset retirement obligations, net | | 3,403 |
| | 2,973 |
|
Note 4. Derivative Instruments
The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in the unaudited condensed consolidated statements of income under the caption “Gain on derivative instruments, net.”
The Company has utilized swap and collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.
With respect to a fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price, and neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price.
The Company’s derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing or Inter-Continental Exchange (“ICE”) pricing for Brent crude oil and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 5. Fair Value Measurements.
At June 30, 2013, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below.
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | Collars |
Crude Oil - NYMEX WTI | | | | Swaps Weighted Average Price | | Floors | | Ceilings |
| | | | | | | Weighted Average Price | | | | Weighted Average Price |
Period and Type of Contract | | Bbls | | | Range | | | Range | |
July 2013 - December 2013 | | | | | | | | | | | | |
Swaps - WTI | | 5,796,000 |
| | $ | 92.65 |
| | | | | | | | |
Collars - WTI | | 4,416,000 |
| | | | $80.00 - $95.00 | | $ | 86.92 |
| | $92.30 - $110.33 | | $ | 99.46 |
|
January 2014 - December 2014 | | | | | | | | | | | | |
Swaps - WTI | | 10,311,250 |
| | $ | 96.20 |
| | | | | | | | |
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | Collars |
Crude Oil - ICE Brent | | | | Swaps Weighted Average Price | | Floors | | Ceilings |
| | | | | | | Weighted Average Price | | | | Weighted Average Price |
Period and Type of Contract | | Bbls | | | Range | | | Range | |
July 2013 - December 2013 | | | | | | | | | | | | |
Swaps - ICE Brent | | 2,484,000 |
| | $ | 108.72 |
| | | | | | | | |
January 2014 - December 2014 | | | | | | | | | | | | |
Swaps - ICE Brent | | 13,687,500 |
| | $ | 102.52 |
| | | | | | | | |
Collars - ICE Brent | | 2,190,000 |
| | | | $90.00 - $95.00 | | $ | 90.83 |
| | $104.70 - $108.85 | | $ | 107.13 |
|
January 2015 - December 2015 | | | | | | | | | | | | |
Swaps - ICE Brent | | 1,277,500 |
| | $ | 98.48 |
| | | | | | | | |
|
| | | | | | | |
Natural Gas - NYMEX Henry Hub | | Swaps Weighted Average Price |
| |
| |
Period and Type of Contract | | MMBtus | |
July 2013 - December 2013 | | | | |
Swaps - Henry Hub | | 46,000,000 |
| | $ | 3.78 |
|
January 2014 - March 2014 | | | | |
Swaps - Henry Hub | | 14,400,000 |
| | $ | 4.30 |
|
April 2014 - December 2014 | |
| |
|
Swaps - Henry Hub | | 30,250,000 |
| | $ | 4.14 |
|
Derivative gains and losses
The following table presents realized and unrealized gains and losses on derivative instruments for the periods presented. |
| | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
In thousands | |
|
Realized gain (loss) on derivatives: | | | | | | | | |
Crude oil fixed price swaps | | $ | 2,081 |
| | $ | (6,367 | ) | | $ | (7,512 | ) | | $ | (37,791 | ) |
Crude oil collars | | 254 |
| | (4,048 | ) | | 379 |
| | (14,968 | ) |
Natural gas fixed price swaps | | (7,087 | ) | | 3,359 |
| | (4,429 | ) | | 5,778 |
|
Realized loss on derivatives, net | | $ | (4,752 | ) | | $ | (7,056 | ) | | $ | (11,562 | ) | | $ | (46,981 | ) |
Unrealized gain (loss) on derivatives: | | | | | | | | |
Crude oil fixed price swaps | | $ | 141,912 |
| | $ | 329,545 |
| | $ | 108,548 |
| | $ | 248,547 |
|
Crude oil collars | | 15,968 |
| | 158,053 |
| | 2,206 |
| | 99,110 |
|
Natural gas fixed price swaps | | 45,928 |
| | (8,814 | ) | | 15,033 |
| | 1,995 |
|
Unrealized gain on derivatives, net | | $ | 203,808 |
| | $ | 478,784 |
| | $ | 125,787 |
| | $ | 349,652 |
|
Gain on derivative instruments, net | | $ | 199,056 |
| | $ | 471,728 |
| | $ | 114,225 |
| | $ | 302,671 |
|
Balance sheet offsetting of derivative assets and liabilities
In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)–Disclosures about Offsetting Assets and Liabilities, which requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The Company adopted the provisions of the new standard on January 1, 2013 as required and has provided the applicable disclosures below with respect to its derivative instruments.
All of the Company’s derivative contracts are carried at their fair value in the condensed consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
liabilities”. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets.
The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2013 | | December 31, 2012 |
In thousands | | Gross amounts of recognized assets | | Gross amounts offset on balance sheet | | Net amounts of assets on balance sheet | | Gross amounts of recognized assets | | Gross amounts offset on balance sheet | | Net amounts of assets on balance sheet |
Commodity derivative assets | | $ | 185,882 |
| | $ | (17,838 | ) | | $ | 168,044 |
| | $ | 86,506 |
| | $ | (35,886 | ) | | $ | 50,620 |
|
| | | | | | | | | | | | |
| | June 30, 2013 | | December 31, 2012 |
In thousands | | Gross amounts of recognized liabilities | | Gross amounts offset on balance sheet | | Net amounts of liabilities on balance sheet | | Gross amounts of recognized liabilities | | Gross amounts offset on balance sheet | | Net amounts of liabilities on balance sheet |
Commodity derivative liabilities | | $ | (8,285 | ) | | $ | 1,476 |
| | $ | (6,809 | ) | | $ | (16,241 | ) | | $ | 1,069 |
| | $ | (15,172 | ) |
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.
|
| | | | | | | | |
In thousands | | June 30, 2013 | | December 31, 2012 |
Derivative assets | | $ | 76,478 |
| | $ | 18,389 |
|
Noncurrent derivative assets | | 91,566 |
| | 32,231 |
|
Net amounts of assets on balance sheet | | $ | 168,044 |
| | $ | 50,620 |
|
Derivative liabilities | | $ | (6,809 | ) | | $ | (12,999 | ) |
Noncurrent derivative liabilities | | — |
| | (2,173 | ) |
Net amounts of liabilities on balance sheet | | $ | (6,809 | ) | | $ | (15,172 | ) |
Total derivative assets, net | | $ | 161,235 |
| | $ | 35,448 |
|
Note 5. Fair Value Measurements
The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
| |
• | Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. |
| |
• | Level 2: Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. |
| |
• | Level 3: Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. |
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. In determining the fair values of fixed price swaps, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of fixed price swaps are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collar contracts requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation for each of its derivative positions is compared to the counterparty valuation for reasonableness.
The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012.
|
| | | | | | | | | | | | | | | | |
| | Fair value measurements at June 30, 2013 using: | | |
In thousands | | Level 1 | | Level 2 | | Level 3 | | Total |
Description | |
|
Derivative assets (liabilities): | | | | | | | | |
Fixed price swaps | | $ | — |
| | $ | 160,297 |
| | $ | — |
| | $ | 160,297 |
|
Collars | | — |
| | 938 |
| | — |
| | 938 |
|
Total | | $ | — |
| | $ | 161,235 |
| | $ | — |
| | $ | 161,235 |
|
| | | | | | | | |
| | Fair value measurements at December 31, 2012 using: | | |
In thousands | | Level 1 | | Level 2 | | Level 3 | | Total |
Description | |
|
Derivative assets (liabilities): | | | | | | | | |
Fixed price swaps | | $ | — |
| | $ | 36,716 |
| | $ | — |
| | $ | 36,716 |
|
Collars | | — |
| | (1,268 | ) | | — |
| | (1,268 | ) |
Total | | $ | — |
| | $ | 35,448 |
| | $ | — |
| | $ | 35,448 |
|
Assets Measured at Fair Value on a Nonrecurring Basis
Certain assets are reported at fair value on a nonrecurring basis in the condensed consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.
Asset Impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on management’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.
|
| | |
Unobservable Input | | Assumption |
Future production | | Future production estimates for each property |
Forward commodity prices | | Forward NYMEX swap prices through 2017 (adjusted for differentials), escalating 3% per year thereafter |
Operating and development costs | | Estimated costs for the current year, escalating 3% per year thereafter |
Productive life of field | | Ranging from 0 to 50 years |
Discount rate | | 10% |
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
At June 30, 2013 and 2012, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows and, therefore, were impaired. Impairments of proved properties amounted to $39.6 million for the six months ended June 30, 2013, all of which was recognized in the second quarter. Such impairments primarily reflected uneconomic results for certain wells drilled on the Company's acreage in the Niobrara play in Colorado and Wyoming. The impaired properties were written down to their estimated fair value totaling approximately $22.2 million as of June 30, 2013. Impairment provisions for proved properties totaled $4.3 million for the three and six months ended June 30, 2012, primarily reflecting uneconomic results in a non-Woodford single-well field in the Company's South region. Those impaired properties were written down to their estimated fair value totaling approximately $2.2 million as of June 30, 2012.
Certain unproved crude oil and natural gas properties were impaired during the three and six months ended June 30, 2013 and 2012, reflecting recurring amortization of undeveloped leasehold costs on properties that management expects will not be transferred to proved properties over the lives of the leases based on experience of successful drilling and the average holding period.
The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of income. |
| | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
In thousands | |
|
Proved property impairments | | $ | 39,635 |
| | $ | 4,332 |
| | $ | 39,635 |
| | $ | 4,332 |
|
Unproved property impairments | | 40,077 |
| | 31,539 |
| | 80,158 |
| | 61,446 |
|
Total | | $ | 79,712 |
| | $ | 35,871 |
| | $ | 119,793 |
| | $ | 65,778 |
|
Financial Instruments Not Recorded at Fair Value
The following table sets forth the fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.
|
| | | | | | | | | | | | | | | | |
| | June 30, 2013 | | December 31, 2012 |
In thousands | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Debt: | | |
Revolving credit facility | | $ | — |
| | $ | — |
| | $ | 595,000 |
| | $ | 595,000 |
|
Note payable | | 19,452 |
| | 18,178 |
| | 20,421 |
| | 20,148 |
|
8 1/4% Senior Notes due 2019 | | 298,192 |
| | 327,750 |
| | 298,085 |
| | 339,000 |
|
7 3/8% Senior Notes due 2020 | | 198,621 |
| | 219,000 |
| | 198,552 |
| | 226,833 |
|
7 1/8% Senior Notes due 2021 | | 400,000 |
| | 438,700 |
| | 400,000 |
| | 454,333 |
|
5% Senior Notes due 2022 | | 2,026,536 |
| | 2,019,200 |
| | 2,027,663 |
| | 2,165,833 |
|
4 1/2% Senior Notes due 2023 | | 1,500,000 |
| | 1,455,000 |
| | — |
| | — |
|
Total debt | | $ | 4,442,801 |
| | $ | 4,477,828 |
| | $ | 3,539,721 |
| | $ | 3,801,147 |
|
The fair value of any revolving credit facility borrowings approximates the carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.
The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
The fair values of the 8 1/4% Senior Notes due 2019 (“2019 Notes”), the 7 3/8% Senior Notes due 2020 (“2020 Notes”), the 7 1/8% Senior Notes due 2021 (“2021 Notes”), the 5% Senior Notes due 2022 (“2022 Notes”), and the 4 1/2% Senior Notes due 2023 ("2023 Notes") are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.
Note 6. Long-Term Debt
Long-term debt consists of the following:
|
| | | | | | | | |
| | June 30, 2013 | | December 31, 2012 |
In thousands | |
|
Revolving credit facility | | $ | — |
| | $ | 595,000 |
|
Note payable | | 19,452 |
| | 20,421 |
|
8 1/4% Senior Notes due 2019 (1) | | 298,192 |
| | 298,085 |
|
7 3/8% Senior Notes due 2020 (2) | | 198,621 |
| | 198,552 |
|
7 1/8% Senior Notes due 2021 (3) | | 400,000 |
| | 400,000 |
|
5% Senior Notes due 2022 (4) | | 2,026,536 |
| | 2,027,663 |
|
4 1/2% Senior Notes due 2023 (3) | | 1,500,000 |
| | — |
|
Total debt | | 4,442,801 |
| | 3,539,721 |
|
Less: Current portion of long-term debt | | (1,981 | ) | | (1,950 | ) |
Long-term debt, net of current portion | | $ | 4,440,820 |
| | $ | 3,537,771 |
|
| |
(1) | The carrying amount is net of unamortized discounts of $1.8 million and $1.9 million at June 30, 2013 and December 31, 2012, respectively. |
| |
(2) | The carrying amount is net of unamortized discounts of $1.4 million at both June 30, 2013 and December 31, 2012. |
| |
(3) | These notes were sold at par and are recorded at 100% of face value. |
| |
(4) | The carrying amount includes an unamortized premium of $26.5 million and $27.7 million at June 30, 2013 and December 31, 2012, respectively. |
Revolving Credit Facility
On April 3, 2013, certain terms of the Company’s credit facility were amended. The amendment included, among other things, the following changes:
| |
• | Allows the Company to elect to suspend the need to comply with borrowing base requirements under the credit facility if either Moody’s or Standard & Poor’s (“S&P”) rates the Company’s senior unsecured debt at or above Ba1 (in the case of Moody’s) or BB+ (in the case of S&P). Previously, the credit facility required both Moody’s and S&P to provide those respective debt ratings before the Company could elect to suspend the borrowing base requirements. |
| |
• | Allows the Company to elect to release the collateral consisting of crude oil and natural gas properties if either Moody’s or S&P rates the Company’s senior unsecured debt at or above Baa3 (in the case of Moody’s) or BBB- (in the case of S&P) (collectively, the “Collateral Release Ratings”), but requires the Company to continue certain reporting requirements and maintain a ratio of the Present Value, as defined in the amended credit facility, of the Company’s crude oil and natural gas properties to all funded debt of the Company of not less than 1.75 to 1.0 (the “Present Value Covenant”) during the period that only one of Moody’s or S&P has issued a rating at or above the Collateral Release Ratings. Previously, the credit facility required both Moody’s and S&P to rate the Company’s senior unsecured debt at or above the Collateral Release Ratings before the collateral from crude oil and natural gas properties could be released. |
| |
• | Provides that if at least one of Moody’s or S&P has not rated the Company’s senior unsecured debt at or above the Collateral Release Ratings, the Company must provide an acceptable security interest in the lesser of (i) crude oil and natural gas properties of the Company representing 80% of the Present Value of such properties and (ii) such of the Company’s proved reserves and associated crude oil and natural gas properties sufficient to provide a Collateral Coverage Ratio, as defined in the amended credit facility, of at least 1.75 to 1.0. |
| |
• | Provides that if both Moody’s and S&P rate the Company’s senior unsecured debt at or above the Collateral Release Ratings, the Company is not required to comply with certain reporting requirements and the Present Value Covenant. The Company will again be required to comply with such reporting requirements and the Present Value Covenant at such |
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
time as both Moody’s and S&P do not rate the Company’s senior unsecured debt at or above the Collateral Release Ratings.
The Company had no outstanding borrowings at June 30, 2013 on its credit facility, which matures on July 1, 2015. At December 31, 2012, the Company had $595.0 million of outstanding borrowings on its credit facility. The credit facility had aggregate commitments of $1.5 billion and a borrowing base of $4.25 billion at June 30, 2013, subject to semi-annual redetermination. The most recent borrowing base redetermination was completed in May 2013, whereby the lenders approved an increase in the Company’s borrowing base from $3.25 billion to $4.25 billion. The terms of the facility allow for the commitment level to be increased up to the lesser of the borrowing base then in effect or $2.5 billion. Borrowings under the facility bear interest at a rate per annum equal to the London Interbank Offered Rate (LIBOR) for one, two, three or six months, as elected by the Company, plus a margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized, or the lead bank’s reference rate (prime) plus a margin ranging from 50 to 150 basis points.
The Company had approximately $1.5 billion of unused commitments under its credit facility at June 30, 2013 and incurs commitment fees of 0.375% per annum of the daily average amount of unused borrowing availability. The credit facility contains certain restrictive covenants including a requirement that the Company maintain a current ratio of not less than 1.0 to 1.0 and a ratio of total funded debt to EBITDAX of no greater than 4.0 to 1.0. As defined by the credit facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available borrowing capacity under the credit facility and exclusive of current balances associated with derivative contracts and asset retirement obligations. 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. Reconciliations of net income and operating cash flows to EBITDAX are provided in Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures. The total funded debt to EBITDAX ratio represents the sum of outstanding borrowings and letters of credit on the credit facility plus the Company’s note payable and senior note obligations, divided by total EBITDAX for the most recent four quarters. The Company was in compliance with these covenants at June 30, 2013.
Senior Notes
On April 5, 2013, the Company issued $1.5 billion of 4 1/2% Senior Notes due 2023 and received net proceeds of approximately $1.48 billion after deducting the initial purchasers’ fees. The Company used a portion of the net proceeds from the offering to repay all borrowings then outstanding under its credit facility, which had a balance prior to payoff of approximately $1.04 billion, and has been using the remaining net proceeds to fund a portion of its 2013 capital budget and for general corporate purposes. The 2023 Notes will mature on April 15, 2023 and interest is payable on the 2023 Notes on April 15 and October 15 of each year, commencing October 15, 2013.
The following table summarizes the maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at June 30, 2013.
|
| | | | | | | | | | |
| | 2019 Notes | | 2020 Notes | | 2021 Notes | | 2022 Notes | | 2023 Notes |
Maturity date | | Oct 1, 2019 | | Oct 1, 2020 | | April 1, 2021 | | Sep 15, 2022 | | April 15, 2023 |
Interest payment dates | | April 1, Oct. 1 | | April 1, Oct. 1 | | April 1, Oct. 1 | | March 15, Sept. 15 | | April 15, Oct. 15 |
Call premium redemption period (1) | | Oct 1, 2014 | | Oct 1, 2015 | | April 1, 2016 | | March 15, 2017 | | n/a |
Make-whole redemption period (2) | | Oct 1, 2014 | | Oct 1, 2015 | | April 1, 2016 | | March 15, 2017 | | Jan 15, 2023 |
Equity offering redemption period (3) | | — | | Oct 1, 2013 | | April 1, 2014 | | March 15, 2015 | | n/a |
| |
(1) | On or after these dates, the Company has the option to redeem all or a portion of its senior notes at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption. |
| |
(2) | At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes at the “make-whole” redemption prices specified in the Indentures plus any accrued and unpaid interest to the date of redemption. |
| |
(3) | At any time prior to these dates, the Company may redeem up to 35% of the principal amount of its senior notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the Indentures plus any accrued and unpaid interest to the date of redemption. The optional redemption period for the 2019 Notes using equity offering proceeds expired on October 1, 2012. |
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
The Indentures, excluding the indenture governing the 2023 Notes, contain certain restrictions on the Company’s ability to incur additional debt, pay dividends on common stock, make certain investments, create certain liens on assets, engage in certain transactions with affiliates, transfer or sell certain assets, consolidate or merge, or sell substantially all of the Company’s assets. The indenture governing the 2023 Notes is less restrictive and contains covenants that limit the Company's ability to create liens securing certain indebtedness and consolidate, merge or transfer certain assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at June 30, 2013. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have insignificant assets with no current value and no operations, fully and unconditionally guarantee the senior notes. The Company’s other subsidiary, 20 North Broadway Associates LLC, the value of whose assets and operations are minor, does not guarantee the senior notes.
Note Payable
In February 2012, 20 North Broadway Associates LLC, a wholly-owned subsidiary of the Company, borrowed $22 million under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.0 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, 2013.
Note 7. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of June 30, 2013. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.
Drilling commitments – As of June 30, 2013, the Company had drilling rig contracts with various terms extending through August 2014. These contracts were entered into in the ordinary course of business to ensure rig availability to allow the Company to execute its business objectives in its key strategic plays. Future commitments as of June 30, 2013 total approximately $65 million, of which $48 million is expected to be incurred in the remainder of 2013 and $17 million in 2014.
Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity totaling 15,000 barrels of crude oil per day on operational crude oil pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have 5-year terms extending as far as November 2017, require the Company to pay varying per-barrel transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of June 30, 2013 under the operational crude oil pipeline transportation arrangements amount to approximately $50 million, of which $7 million is expected to be incurred in the remainder of 2013, $14 million in 2014, $14 million in 2015, $10 million in 2016 and $5 million in 2017.
The Company has also entered into a commitment to guarantee pipeline access capacity on an operational natural gas pipeline system to move a portion of its North region natural gas production to market. The commitment, which has a 10-year term ending in October 2023, requires the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments under the arrangement amount to approximately $25 million, which is expected to be incurred ratably over its 10-year term.
Further, the Company is a party to additional 5-year firm transportation commitments for future pipeline projects being considered for development that are not yet operational. Such projects require the granting of regulatory approvals or otherwise require significant additional construction efforts by the counterparties before being completed. Future commitments under the non-operational arrangements total approximately $1.0 billion at June 30, 2013, including approximately $96 million with an affiliate controlled by the Company's Chairman of the Board, Chief Executive Officer and principal shareholder. These commitments represent aggregate transportation charges expected to be incurred over the 5-year terms of the arrangements assuming the proposed pipeline projects are completed and become operational. The timing of the commencement of pipeline operations is not known due to uncertainties involving matters such as regulatory approvals, resolution of legal and environmental disputes, construction progress and the ultimate probability of pipeline completion. Accordingly, the timing of the Company’s obligations under these non-operational arrangements cannot be predicted with certainty and may not be incurred on a ratable basis over a calendar year or may not be incurred at all. Although timing is uncertain, the Company’s obligations under these arrangements are not expected to begin until at least 2014.
Rail transportation commitments – The Company has entered into firm transportation commitments to guarantee capacity on rail transportation facilities in order to reduce the impact of possible curtailments that may arise due to limited transportation capacity. The rail commitments have various terms extending through December 2014 and require the Company to pay varying per-barrel transportation charges on volumes ranging from 2,500 to 10,000 barrels of crude oil per day
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
regardless of the amount of rail capacity used. Future commitments remaining as of June 30, 2013 under the rail transportation arrangements amount to approximately $27 million, of which $17 million is expected to be incurred in the remainder of 2013 and $10 million in 2014.
The Company’s pipeline and rail transportation commitments are for production primarily in the North region where the Company allocates a significant portion of its capital expenditures. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.
Litigation – In November 2010, an alleged class action was filed against the Company alleging the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The Company has responded to the petition, denied the allegations and raised a number of affirmative defenses. Discovery is ongoing and information and documents continue to be exchanged. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The class has not been certified. Plaintiffs have indicated that if the class is certified they may seek damages in excess of $165 million, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes that the case meets the requirements for a class action and is vigorously defending the case.
The Company is involved in various other legal proceedings such as commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and similar matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of June 30, 2013 and December 31, 2012, the Company has recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $1.7 million and $2.4 million, respectively, for various matters, none of which are believed to be individually significant.
Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.
Note 8. Stock-Based Compensation
The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) and 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of income, is reflected in the table below for the periods presented.
|
| | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
In thousands | | |
Non-cash equity compensation | | $ | 9,756 |
| | $ | 7,790 |
| | $ | 18,998 |
| | $ | 13,305 |
|
In May 2013, the Company's shareholders, upon recommendation by the Board of Directors, approved the adoption of the Company's 2013 Plan. The 2013 Plan is a broad-based incentive plan that allows the Company to use, if desired, a variety of equity compensation alternatives in structuring compensation arrangements for the Company's officers, directors and key employees. Effective May 23, 2013, the 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms.
The maximum number of shares of common stock available for issuance under the 2013 Plan will be 9,840,036 shares, which includes (i) 7,500,000 new shares authorized under the 2013 Plan, (ii) 1,840,036 shares that remained available for issuance under the 2005 Plan as of March 27, 2013 that have been transferred from the 2005 Plan to the 2013 Plan, and (iii) up to 500,000 shares available for issuance under the 2013 Plan to the extent such shares are forfeited or withheld for payment of income taxes related to existing awards outstanding under the 2005 Plan. As of June 30, 2013, the Company had a maximum of 9,829,816 shares of restricted stock available to grant to officers, directors and key employees under the 2013 Plan.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock or to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years.
A summary of changes in non-vested restricted stock shares outstanding for the six months ended June 30, 2013 is presented below:
|
| | | | | | | |
| | Number of non-vested shares | | Weighted average grant-date fair value |
Non-vested restricted shares outstanding at December 31, 2012 | | 1,629,462 |
| | $ | 63.28 |
|
Granted | | 129,850 |
| | 83.94 |
|
Vested | | (124,777 | ) | | 60.65 |
|
Forfeited | | (52,823 | ) | | 72.47 |
|
Non-vested restricted shares outstanding at June 30, 2013 | | 1,581,712 |
| | $ | 67.52 |
|
The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is a fixed amount determined at the grant date fair value and is recognized ratably over the vesting period as services are rendered by employees and directors. The expected life of restricted stock is based on the non-vested period that remains subsequent to the date of grant. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value of restricted stock that vested during the six months ended June 30, 2013 at the vesting date was approximately $10.4 million. As of June 30, 2013, there was approximately $62 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.6 years.
Note 9. 2012 Property Dispositions
In February 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Wyoming to a third party for cash proceeds of $84.4 million. In connection with the transaction, the Company recognized a pre-tax gain of $50.1 million. The disposed properties comprised 3.2 MMBoe, or 1%, of the Company’s total proved reserves at December 31, 2011 and 259 MBoe, or 1%, of its 2011 total crude oil and natural gas production.
In June 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Oklahoma to a third party for $15.9 million and recognized a pre-tax gain on the transaction of $15.9 million. The disposed properties represented an immaterial portion of the Company’s total proved reserves and production.
The gains on the above dispositions are included in the caption “(Gain) loss on sale of assets, net” in the unaudited condensed consolidated statements of income for the respective 2012 periods.
| |
ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2012. Our operating results for the periods discussed below may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described under the heading Part II, Item 1A. Risk Factors included in this report, if any, and in our Annual Report on Form 10-K for the year ended December 31, 2012, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
We are an independent crude oil and natural gas exploration and production company with properties in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi River including the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma Woodford plays in Oklahoma. The SCOOP and Northwest Cana plays were previously combined by us and referred to as the Anadarko Woodford play. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River. Our operations are geographically concentrated in the North region, with that region comprising approximately 77% of our crude oil and natural gas production and approximately 87% of our crude oil and natural gas revenues for the six months ended June 30, 2013.
We focus our exploration activities in large new or developing crude oil and liquids-rich natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce crude oil and natural gas reserves from unconventional formations. In October 2012, we announced a five-year growth plan to triple our production and proved reserves from year-end 2012 to year-end 2017.
We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas. We expect growth in our revenues and operating income will primarily depend on commodity prices and our ability to increase our crude oil and natural gas production. In recent months and years, there has been significant volatility in crude oil and natural gas prices due to a variety of factors we cannot control or predict, including political and economic events, weather conditions, and competition from other energy sources. These factors impact supply and demand for crude oil and natural gas, which affect crude oil and natural gas prices. In addition, the prices we realize for our crude oil and natural gas production are affected by price differences in the markets where we deliver our production.
2013 Highlights
Production, revenues and operating cash flows
For the second quarter of 2013, our crude oil and natural gas production averaged 135,700 Boe per day, representing a 12% increase over average daily production of 121,532 Boe per day for the first quarter of 2013 and a 43% increase over average daily production of 94,852 Boe per day for the second quarter of 2012. Crude oil and natural gas production averaged 128,655 Boe per day for the six months ended June 30, 2013, a 43% increase over average daily production of 90,189 Boe per day for the comparable 2012 period. Crude oil represented 71% of our total production for the three and six months ended June 30, 2013 compared to 69% for the three and six months ended June 30, 2012.
The increase in 2013 production was primarily driven by higher production from our properties in the North Dakota Bakken field and the SCOOP play due to the continued success of our drilling programs in those areas.
Our Bakken production in North Dakota averaged 72,268 Boe per day for the first half of 2013, a 62% increase over the first half of 2012. Second quarter 2013 average daily production in North Dakota Bakken averaged 76,909 Boe per day, a 14% increase over the first quarter of 2013 and 63% higher than the second quarter of 2012.
Production in the emerging SCOOP play averaged 15,904 Boe per day for the first half of 2013, 447% higher than the comparable period in 2012. SCOOP average daily production totaled 17,547 Boe per day for the second quarter of 2013, an increase of 23% over the first quarter of 2013 and 435% higher than the 2012 second quarter.
Crude oil and natural gas revenues for the second quarter of 2013 increased 70% to $892.2 million primarily due to a 48% increase in sales volumes along with a 15% increase in realized commodity prices when compared to the second quarter of 2012. For the six months ended June 30, 2013, crude oil and natural gas revenues totaled $1.7 billion, a 56% increase from the comparable 2012 period, due to a 44% increase in sales volumes along with an 8% increase in realized commodity prices. Crude oil represented 87% and 88% of our total crude oil and natural gas revenues for the three and six months ended June 30, 2013, respectively, compared to 89% for both the three and six months ended June 30, 2012.
Cash flows from operating activities for the six months ended June 30, 2013 were $1,156.9 million, a 50% increase from $770.8 million provided by our operating activities during the comparable 2012 period. The increase in operating cash flows in 2013 was primarily due to increased crude oil and natural gas revenues driven by higher sales volumes and higher realized commodity prices coupled with lower realized losses on derivatives, partially offset by higher production expenses, production taxes, general and administrative expenses, and other expenses associated with the growth of our operations over the past year.
Capital expenditures
Our capital expenditures budget for 2013 is $3.6 billion, excluding acquisitions. For the six months ended June 30, 2013, we invested approximately $1.8 billion in our capital program, excluding $122.7 million of unbudgeted acquisitions and including $8.2 million of seismic costs and $59.4 million of capital costs associated with increased accruals for capital expenditures. Capital expenditures for the second quarter of 2013 totaled $896.9 million, excluding $100.7 million of unbudgeted acquisitions. Our 2013 capital program is focused primarily on increased exploration and development in the Bakken field of North Dakota and Montana and the SCOOP play in south-central Oklahoma. We expect to continue participating as a buyer of properties if and when we have the ability to increase our position in strategic plays at favorable terms.
We hedge a portion of our anticipated future production to achieve more predictable cash flows and reduce our exposure to fluctuations in commodity prices. Reducing our exposure to price volatility helps ensure adequate funds are available for our capital program. We expect our cash flows from operations, our remaining cash balance, and our credit facility, including our ability to increase our borrowing capacity thereunder, will be sufficient to meet our budgeted capital expenditure needs for 2013; however, we may choose to access the capital markets for additional financing to take advantage of business opportunities that may arise if such financing can be arranged at favorable terms.
Issuance of new senior notes
On April 5, 2013, we issued $1.5 billion of 4 1/2% Senior Notes due 2023 (the “2023 Notes”) and received net proceeds of approximately $1.48 billion after deducting the initial purchasers’ fees. We used a portion of the net proceeds from the offering to repay all borrowings then outstanding under our credit facility, which had a balance prior to payoff of approximately $1.04 billion. The remaining net proceeds from the issuance of approximately $0.4 billion are being used to fund a portion of our 2013 capital budget and for general corporate purposes. The 2023 Notes will mature on April 15, 2023 and interest is payable on the 2023 Notes on April 15 and October 15 of each year, commencing October 15, 2013.
Financial and operating highlights
We use a variety of financial and operating measures to assess our performance. Among these measures are:
| |
• | Volumes of crude oil and natural gas produced, |
| |
• | Crude oil and natural gas prices realized, |
| |
• | Per unit operating and administrative costs, and |
| |
• | EBITDAX (a non-GAAP financial measure). |
The following table presents financial and operating highlights for the periods presented.
|
| | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
Average daily production: | |
| |
| |
| |
|
Crude oil (Bbl per day) | | 96,029 |
| | 65,274 |
| | 91,077 |
| | 62,587 |
|
Natural gas (Mcf per day) | | 238,028 |
| | 177,471 |
| | 225,467 |
| | 165,611 |
|
Crude oil equivalents (Boe per day) | | 135,700 |
| | 94,852 |
| | 128,655 |
| | 90,189 |
|
Average sales prices: (1) | |
| |
| |
| |
|
Crude oil ($/Bbl) | | $ | 87.22 |
| | $ | 80.56 |
| | $ | 88.50 |
| | $ | 85.40 |
|
Natural gas ($/Mcf) | | 5.22 |
| | 3.51 |
| | 5.11 |
| | 3.96 |
|
Crude oil equivalents ($/Boe) | | 71.13 |
| | 61.69 |
| | 71.68 |
| | 66.31 |
|
Production expenses ($/Boe) (1) | | 5.86 |
| | 5.16 |
| | 5.79 |
| | 5.17 |
|
General and administrative expenses ($/Boe) (1) | | 2.86 |
| | 3.51 |
| | 2.98 |
| | 3.38 |
|
Net income (in thousands) | | $ | 323,270 |
| | $ | 405,684 |
| | $ | 463,897 |
| | $ | 474,778 |
|
Diluted net income per share | | $ | 1.75 |
| | $ | 2.25 |
| | $ | 2.51 |
| | $ | 2.63 |
|
EBITDAX (in thousands) (2) | | 708,107 |
| | 421,860 |
| | 1,329,635 |
| | 876,392 |
|
| |
(1) | Average sales prices and per unit expenses have been calculated using sales volumes and exclude any effect of derivative transactions. |
| |
(2) | 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. Reconciliations of net income and operating cash flows to EBITDAX are provided subsequently under the heading Non-GAAP Financial Measures. |
Three months ended June 30, 2013 compared to the three months ended June 30, 2012
Results of Operations
The following table presents selected financial and operating information for the periods presented.
|
| | | | | | | | |
| | Three months ended June 30, |
| | 2013 | | 2012 |
In thousands, except sales price data | | |
Crude oil and natural gas sales | | $ | 892,187 |
| | $ | 523,393 |
|
Gain on derivative instruments, net (1) | | 199,056 |
| | 471,728 |
|
Crude oil and natural gas service operations | | 9,509 |
| | 9,598 |
|
Total revenues | | 1,100,752 |
| | 1,004,719 |
|
Operating costs and expenses | | 526,880 |
| | 318,245 |
|
Other expenses, net | | 60,744 |
| | 30,902 |
|
Income before income taxes | | 513,128 |
| | 655,572 |
|
Provision for income taxes | | 189,858 |
| | 249,888 |
|
Net income | | $ | 323,270 |
| | $ | 405,684 |
|
Production volumes: | |
| |
|
Crude oil (MBbl) (2) | | 8,739 |
| | 5,940 |
|
Natural gas (MMcf) | | 21,661 |
| | 16,150 |
|
Crude oil equivalents (MBoe) | | 12,349 |
| | 8,632 |
|
Sales volumes: | |
| |
|
Crude oil (MBbl) (2) | | 8,932 |
| | 5,793 |
|
Natural gas (MMcf) | | 21,661 |
| | 16,150 |
|
Crude oil equivalents (MBoe) | | 12,542 |
| | 8,485 |
|
Average sales prices: (3) | |
| |
|
Crude oil ($/Bbl) | | $ | 87.22 |
| | $ | 80.56 |
|
Natural gas ($/Mcf) | | 5.22 |
| | 3.51 |
|
Crude oil equivalents ($/Boe) | | 71.13 |
| | 61.69 |
|
| |
(1) | Amounts include unrealized non-cash mark-to-market gains on derivatives of $203.8 million and $478.8 million for the three month periods ended June 30, 2013 and 2012, respectively. |
| |
(2) | At various times we have stored crude oil due to pipeline line fill requirements, low commodity prices, or transportation constraints or we have sold crude oil from inventory. These actions result in differences between produced and sold crude oil volumes. Crude oil sales volumes were 193 MBbls more than crude oil production for the three months ended June 30, 2013 and 147 MBbls less than crude oil production for the three months ended June 30, 2012. |
| |
(3) | Average sales prices have been calculated using sales volumes and exclude any effect of derivative transactions. |
Production
The following tables reflect our production by product and region for the periods presented.
|
| | | | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | Volume increase | | Volume percent increase |
| | 2013 | | 2012 | | |
| | Volume | | Percent | | Volume | | Percent | |
Crude oil (MBbl) | | 8,739 |
| | 71 | % | | 5,940 |
| | 69 | % | | 2,799 |
| | 47 | % |
Natural gas (MMcf) | | 21,661 |
| | 29 | % | | 16,150 |
| | 31 | % | | 5,511 |
| | 34 | % |
Total (MBoe) | | 12,349 |
| | 100 | % | | 8,632 |
| | 100 | % | | 3,717 |
| | 43 | % |
| | | | | | | | | | | | |
| | Three months ended June 30, | | Volume increase (decrease) | | Volume percent increase (decrease) |
| | 2013 | | 2012 | | |
| | MBoe | | Percent | | MBoe | | Percent | |
North Region | | 9,557 |
| | 77 | % | | 6,406 |
| | 74 | % | | 3,151 |
| | 49 | % |
South Region | | 2,792 |
| | 23 | % | | 2,129 |
| | 25 | % | | 663 |
| | 31 | % |
East Region (1) | | — |
| | — |
| | 97 |
| | 1 | % | | (97 | ) | | (100 | %) |
Total | | 12,349 |
| | 100 | % | | 8,632 |
| | 100 | % | | 3,717 |
| | 43 | % |
| |
(1) | In December 2012, we sold the producing crude oil and natural gas properties in our East region and no new wells have been subsequently drilled in that region. Accordingly, no production is reflected for the East region for the three months ended June 30, 2013. |
Crude oil production volumes increased 47% for the three months ended June 30, 2013 compared to the three months ended June 30, 2012. Production increases in the Bakken field and SCOOP play contributed incremental production volumes in 2013 of 3,010 MBbls, a 71% increase over production in these areas for the second quarter of 2012. Production growth in these areas is primarily due to increased drilling and completion activity resulting from our drilling program. These increases were partially offset by a decrease of 93 MBbls associated with non-strategic properties in the East region that were sold in December 2012. Additionally, production from our properties in the Red River units and Northwest Cana play decreased a total of 119 MBbls, or 8%, over the prior year second quarter due to a combination of natural declines in production and reduced drilling activity in those areas.
Natural gas production volumes increased 5,511 MMcf, or 34%, during the three months ended June 30, 2013 compared to the same period in 2012. Natural gas production in the Bakken field increased 3,227 MMcf, or 79%, for the three months ended June 30, 2013 compared to the same period in 2012 due to new wells being completed and gas from existing wells being connected to natural gas processing plants in the play. Natural gas production in the SCOOP play increased 5,350 MMcf, or 401%, due to additional wells being completed and producing in the three months ended June 30, 2013 compared to the same period in 2012. Further, natural gas production increased 336 MMcf, or 81%, in non-Bakken areas of our North region due to the completion of new wells subsequent to the 2012 second quarter. These increases were partially offset by decreases in production volumes totaling 3,373 MMcf, or 34%, from our properties in Northwest Cana, Arkoma Woodford, and non-core areas in our South region due to a combination of natural declines in production and reduced drilling activity prompted by the pricing environment for natural gas in those areas. For 2013, we are allocating a greater portion of our capital expenditures to crude oil and liquids-rich natural gas areas such as the Bakken field and SCOOP play and have temporarily deferred our drilling activity in the Northwest Cana and Arkoma Woodford plays, which typically contain higher concentrations of natural gas. Additionally, natural gas production decreased 26 MMcf associated with non-strategic properties in the East region that were sold in December 2012.
Revenues
Our total revenues consist of sales of crude oil and natural gas, realized and unrealized changes in the fair value of our derivative instruments and revenues associated with crude oil and natural gas service operations.
Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the three months ended June 30, 2013 were $892.2 million, a 70% increase from sales of $523.4 million for the same period in 2012. Our sales volumes increased 4,057 MBoe, or 48%, over the comparable period in 2012 primarily due to the success of our drilling programs in the North Dakota Bakken field and SCOOP play.
Our realized price per Boe increased $9.44 to $71.13 for the three months ended June 30, 2013 from $61.69 for the three months ended June 30, 2012. This increase reflects a significant improvement in crude oil differentials realized in the
2013 second quarter compared to the 2012 second quarter along with higher natural gas prices realized in connection with improved market prices.
The differential between NYMEX West Texas Intermediate ("WTI") calendar month average crude oil prices and our realized crude oil price per barrel for the three months ended June 30, 2013 decreased to $7.07 per barrel compared to $12.63 for the three months ended June 30, 2012 and $9.06 for the year ended December 31, 2012. The improved differential primarily reflects our shift to market and deliver our Bakken crude oil to higher-priced basis markets throughout the United States such as those on the gulf coast, east coast and west coast, with an increased reliance on rail transportation versus pipeline transportation, along with a general improvement in market differentials at conventional pipeline markets. During 2012, using rail transportation we increased our access to market centers on the east and west coasts of the United States and continued our marketing efforts along the U.S. gulf coast. This approach provided expanded flexibility that allowed us to shift sales of our Bakken crude oil to markets that provided us with more favorable pricing. Rail transportation costs are typically higher than pipeline transportation costs per barrel mile; however, the premium received during this period for our North region production sold in U.S. coastal markets compared to mid-continent WTI pricing more than offset the increased transportation costs. The positive effects of stronger pricing in coastal markets began to be realized in the fourth quarter of 2012 and continued into the first half of 2013. In recent months, the spread between mid-continent WTI pricing and pricing in U.S. coastal markets has narrowed. The narrowing of WTI and coastal market pricing could potentially have an adverse impact on our realized NYMEX WTI crude oil differentials if rail transportation continues to have a prominent role in our crude oil deliveries out of the North region and rail transportation costs are not reduced by pressure to compete with pipeline economics.
Derivatives. We have entered into a number of derivative instruments, including fixed price swaps and zero-cost collars, to reduce the uncertainty of future cash flows in order to underpin our capital expenditures and drilling program. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value in the unaudited condensed consolidated statements of income under the caption “Gain on derivative instruments, net”, which is a component of total revenues.
Changes in commodity futures price strips during the second quarter of 2013 had a positive impact on the fair value of our derivatives, which resulted in positive revenue adjustments of $199.1 million for the three months ended June 30, 2013. We expect our revenues will continue to be significantly impacted, either positively or negatively, by changes in the fair value of our derivative instruments as a result of volatility in crude oil and natural gas prices. The following table presents the impact on total revenues related to realized and unrealized gains and losses on derivative instruments for the periods presented.
|
| | | | | | | | |
| | Three months ended June 30, |
| | 2013 |
| 2012 |
In thousands | |
|
Realized gain (loss) on derivatives: | |
| |
|
Crude oil derivatives | | $ | 2,335 |
| | $ | (10,415 | ) |
Natural gas derivatives | | (7,087 | ) | | 3,359 |
|
Realized loss on derivatives, net | | $ | (4,752 | ) | | $ | (7,056 | ) |
Unrealized gain (loss) on derivatives: | |
| |
|
Crude oil derivatives | | $ | 157,880 |
| | $ | 487,598 |
|
Natural gas derivatives | | 45,928 |
| | $ | (8,814 | ) |
Unrealized gain on derivatives, net | | $ | 203,808 |
| | $ | 478,784 |
|
Gain on derivative instruments, net | | $ | 199,056 |
| | $ | 471,728 |
|
The unrealized mark-to-market gains reflected above at June 30, 2013 relate to derivative instruments with various terms that are scheduled to be realized over the period from July 2013 to December 2015. Over this period, actual realized derivative settlements may differ significantly, either positively or negatively, from the unrealized mark-to-market valuation at June 30, 2013.
Operating Costs and Expenses
Production Expenses and Production Taxes and Other Expenses. Production expenses increased 68% to $73.4 million during the three months ended June 30, 2013 from $43.8 million during the three months ended June 30, 2012. This increase is primarily the result of higher production volumes from an increase in the number of producing wells coupled with higher costs incurred as a result of adverse weather conditions in the North region. Production expense per Boe was $5.86 for the three
months ended June 30, 2013 compared to $5.16 per Boe for the three months ended June 30, 2012 and $5.49 per Boe for the year ended December 31, 2012. Contributing to the per-Boe increase were increases in well site and road maintenance costs and saltwater disposal costs resulting from a more severe winter season encountered in 2013, which created a more challenging operating environment compared to a mild winter season experienced in 2012. Adverse weather experienced in the North region for the first quarter of 2013 continued to impact operating conditions into April and May 2013 and resulted in higher per-Boe operating costs compared to the 2012 second quarter.
Production taxes and other expenses increased $33.0 million, or 67%, to $82.2 million during the three months ended June 30, 2013 compared to the three months ended June 30, 2012 primarily as a result of higher crude oil and natural gas revenues resulting from increased sales volumes and higher realized commodity prices. Production taxes and other expenses include charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Oklahoma Woodford and North Dakota Bakken areas of $7.7 million and $6.6 million for the three months ended June 30, 2013 and 2012, respectively. The increase in other charges is primarily due to higher natural gas sales volumes in 2013. Production taxes, excluding other charges, as a percentage of crude oil and natural gas revenues were 8.3% for the three months ended June 30, 2013 compared to 8.1% for the three months ended June 30, 2012. The increase is due to higher taxable revenues coming from North Dakota, our most active area, which has production tax rates of up to 11.5% of crude oil revenues. Production taxes are generally based on the wellhead values of production and vary by state. Some states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of crude oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana and Oklahoma, new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate reverts to the statutory rate. Our overall production tax rate is expected to increase as we continue to grow our operations in North Dakota and as production tax incentives we currently receive for horizontal wells reach the end of their incentive periods.
On a unit of sales basis, production expenses and production taxes and other expenses were as follows for the periods presented:
|
| | | | | | | | |
|
| Three months ended June 30, |
$/Boe |
| 2013 |
| 2012 |
Production expenses | | $ | 5.86 |
| | $ | 5.16 |
|
Production taxes and other expenses | | 6.55 |
| | 5.80 |
|
Production expenses, production taxes and other expenses | | $ | 12.41 |
| | $ | 10.96 |
|
Exploration Expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. The following table shows the components of exploration expenses for the periods presented. |
| | | | | | | | |
|
| Three months ended June 30, |
In thousands |
| 2013 |
| 2012 |
Geological and geophysical costs | | $ | 5,349 |
| | $ | 8,692 |
|
Dry hole costs | | 5,802 |
| | 10 |
|
Exploration expenses | | $ | 11,151 |
| | $ | 8,702 |
|
Geological and geophysical costs decreased $3.3 million for the three months ended June 30, 2013 due to changes in the timing and amount of acquisitions of exploratory seismic data between periods. Dry hole charges recognized in the 2013 second quarter primarily reflect costs associated with exploratory wells in the Arkoma Woodford area of our South region.
Depreciation, Depletion, Amortization and Accretion (“DD&A”). Total DD&A increased $75.8 million, or 47%, in the second quarter of 2013 compared to the second quarter of 2012 primarily due to a 48% increase in sales volumes. The following table shows the components of our DD&A on a unit of sales basis.
|
| | | | | | | | |
|
| Three months ended June 30, |
$/Boe |
| 2013 | | 2012 |
Crude oil and natural gas | | $ | 18.61 |
| | $ | 18.67 |
|
Other equipment | | 0.22 |
| | 0.22 |
|
Asset retirement obligation accretion | | 0.05 |
| | 0.09 |
|
Depreciation, depletion, amortization and accretion | | $ | 18.88 |
| | $ | 18.98 |
|
Property Impairments. Property impairments increased in the three months ended June 30, 2013 by $43.8 million to $79.7 million compared to $35.9 million for the three months ended June 30, 2012.
Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually insignificant non-producing properties are amortized on an aggregate basis based on our estimated experience of successful drilling and the average holding period. Impairments of non-producing properties increased $8.6 million during the three months ended June 30, 2013 to $40.1 million compared to $31.5 million for the three months ended June 30, 2012. The increase resulted from a larger base of amortizable costs in the current period coupled with higher rates of amortization resulting from changes in management's estimates of undeveloped properties not expected to be developed before lease expiration. We currently have no individually significant non-producing properties that are assessed for impairment on a property-by-property basis.
We evaluate proved crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair value using discounted cash flows. Impairments of proved properties amounted to $39.6 million for the three months ended June 30, 2013, primarily reflecting uneconomic results for certain wells drilled on the Company's acreage in the Niobrara play in Colorado and Wyoming. Proved property impairments totaled $4.3 million for the three months ended June 30, 2012, primarily reflecting uneconomic results in a non-Woodford single-well field in our South region.
General and Administrative Expenses. General and administrative expenses (“G&A”) increased $6.1 million, or 20%, to $35.9 million for the three months ended June 30, 2013 from $29.8 million for the comparable period in 2012. G&A expenses include non-cash charges for equity compensation of $9.8 million and $7.8 million for the three months ended June 30, 2013 and 2012, respectively. The increase in equity compensation in 2013 resulted primarily from larger grants of restricted stock being made throughout 2012 and 2013 due to employee growth, which resulted in increased expense recognition in the second quarter of 2013 compared to the second quarter of 2012.
The previously announced relocation of our corporate headquarters from Enid, Oklahoma to Oklahoma City was completed during 2012; however, residual costs continue to be incurred under the terms of the Company's relocation plan offered to employees. For the three months ended June 30, 2013, we recognized $0.7 million of costs associated with our relocation compared to $3.3 million for the three months ended June 30, 2012.
G&A expenses excluding equity compensation and relocation expenses increased $6.7 million for the three months ended June 30, 2013 compared to the same period in 2012. The increase was primarily due to an increase in personnel costs and office-related expenses associated with our rapid growth.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented. The decrease in G&A expenses on a per-unit basis in the 2013 second quarter was due in part to the rapid growth in our crude oil and natural gas sales volumes coupled with improved efficiency of operations compared to the prior year in which our corporate relocation was taking place.
|
| | | | | | | | |
|
| Three months ended June 30, |
$/Boe |
| 2013 | | 2012 |
General and administrative expenses | | $ | 2.03 |
| | $ | 2.20 |
|
Non-cash equity compensation | | 0.78 |
| | 0.92 |
|
Corporate relocation expenses | | 0.05 |
| | 0.39 |
|
Total general and administrative expenses | | $ | 2.86 |
| | $ | 3.51 |
|
Interest Expense. Interest expense increased $29.7 million, or 94%, to $61.4 million for the three months ended June 30, 2013 compared to $31.7 million for the three months ended June 30, 2012 due to an increase in our weighted average outstanding long-term debt obligations. Our weighted average outstanding long-term debt balance for the three months ended June 30, 2013 was approximately $4.4 billion with a weighted average interest rate of 5.3% compared to a weighted average outstanding long-term debt balance of $2.1 billion and a weighted average interest rate of 5.5% for the comparable period in 2012. The increase in outstanding debt resulted from the issuance of $1.2 billion of 5% Senior Notes due 2022 in August 2012 and $1.5 billion of 2023 Notes in April 2013, the net proceeds of which were used to repay credit facility borrowings, to fund a portion of our capital budgets and for general corporate purposes.
Our weighted average outstanding credit facility balance amounted to $84.9 million for the second quarter of 2013 compared to $397.2 million for the second quarter of 2012. The weighted average interest rate on our credit facility borrowings was 2.1% for the second quarter of 2013 compared to 2.2% for the same period in 2012. At June 30, 2013, we had no outstanding borrowings on our credit facility. We had $1.04 billion of outstanding borrowings on our credit facility at March
31, 2013. The decrease in credit facility borrowings in the 2013 second quarter resulted from paying off the outstanding balance in April 2013 using the net proceeds from the issuance of the 2023 Notes, with no subsequent credit facility borrowings.
Income Taxes. We recorded income tax expense for the three months ended June 30, 2013 of $189.9 million compared to $249.9 million for the three months ended June 30, 2012. We provided for income taxes at a combined federal and state tax rate of approximately 37% and 38% for the three months ended June 30, 2013 and 2012, respectively, after taking into account permanent taxable differences.
Six months ended June 30, 2013 compared to the six months ended June 30, 2012
Results of Operations
The following table presents selected financial and operating information for the periods presented.