UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________
FORM 10-Q
_______________________________
(Mark One)
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2014
or
¨ | 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)
_______________________________
Oklahoma | 73-0767549 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
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.
Large accelerated filer | x | Accelerated filer | ¨ | |||
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
186,100,261 shares of our $0.01 par value common stock were outstanding on May 1, 2014.
Table of Contents
Item 1. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 1. | ||
Item 1A. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 5. | ||
Item 6. | ||
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 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.
"gross acres" or "gross wells" Refers to the total acres or wells in which a working interest is owned.
“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.
“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” or "net wells" Refers to the sum of the fractional working interests owned in gross acres or gross wells.
i
“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.
ii
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, if any, our Annual Report on Form 10-K for the year ended December 31, 2013, registration statements filed from time to time with the Securities and Exchange Commission ("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:
• | our business strategy; |
• | our future operations; |
• | our crude oil and natural gas reserves; |
• | our technology; |
• | our financial strategy; |
• | crude oil, natural gas liquids, and natural gas prices and differentials; |
• | the timing and amount of future production of crude oil and natural gas and flaring activities; |
• | the amount, nature and timing of capital expenditures; |
• | estimated revenues, expenses and results of operations; |
• | drilling and completing of wells; |
• | competition; |
• | marketing of crude oil and natural gas; |
• | transportation of crude oil, natural gas liquids, and natural gas to markets; |
• | exploitation or property acquisitions and dispositions; |
• | costs of exploiting and developing our properties and conducting other operations; |
• | our financial position; |
• | general economic conditions; |
• | credit markets; |
• | our liquidity and access to capital; |
• | 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; |
• | our future operating results; |
• | plans, objectives, expectations and intentions contained in this report that are not historical, including, without limitation, statements regarding our future growth plans; |
• | our commodity or other hedging arrangements; and |
• | 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,
iii
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 and transportation infrastructure, environmental risks, drilling and other operating risks, lack of availability and security of computer-based systems, 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, if any, our Annual Report on Form 10-K for the year ended December 31, 2013, 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.
iv
PART I. Financial Information
ITEM 1. | Financial Statements |
Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
March 31, 2014 | December 31, 2013 | |||||||
In thousands, except par values and share data | (Unaudited) | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 51,535 | $ | 28,482 | ||||
Receivables: | ||||||||
Crude oil and natural gas sales | 709,775 | 643,498 | ||||||
Affiliated parties | 17,134 | 13,107 | ||||||
Joint interest and other, net | 330,728 | 349,579 | ||||||
Derivative assets | 799 | 3,616 | ||||||
Inventories | 72,109 | 54,440 | ||||||
Deferred and prepaid taxes | 47,114 | 44,337 | ||||||
Prepaid expenses and other | 12,381 | 10,207 | ||||||
Total current assets | 1,241,575 | 1,147,266 | ||||||
Net property and equipment, based on successful efforts method of accounting | 11,443,951 | 10,721,272 | ||||||
Net debt issuance costs and other | 76,722 | 72,644 | ||||||
Noncurrent derivative assets | 2,653 | — | ||||||
Total assets | $ | 12,764,901 | $ | 11,941,182 | ||||
Liabilities and shareholders’ equity | ||||||||
Current liabilities: | ||||||||
Accounts payable trade | $ | 946,123 | $ | 885,289 | ||||
Revenues and royalties payable | 325,550 | 291,772 | ||||||
Payables to affiliated parties | 6,228 | 5,436 | ||||||
Accrued liabilities and other | 189,291 | 198,113 | ||||||
Derivative liabilities | 98,493 | 90,535 | ||||||
Current portion of long-term debt | 2,029 | 2,011 | ||||||
Total current liabilities | 1,567,714 | 1,473,156 | ||||||
Long-term debt, net of current portion | 5,067,814 | 4,713,821 | ||||||
Other noncurrent liabilities: | ||||||||
Deferred income tax liabilities | 1,872,457 | 1,736,812 | ||||||
Asset retirement obligations, net of current portion | 56,066 | 54,353 | ||||||
Noncurrent derivative liabilities | 6,117 | 7,829 | ||||||
Other noncurrent liabilities | 6,972 | 2,093 | ||||||
Total other noncurrent liabilities | 1,941,612 | 1,801,087 | ||||||
Commitments and contingencies (Note 7) | ||||||||
Shareholders’ equity: | ||||||||
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding | — | — | ||||||
Common stock, $0.01 par value; 500,000,000 shares authorized; 186,080,087 shares issued and outstanding at March 31, 2014; 185,658,659 shares issued and outstanding at December 31, 2013 | 1,861 | 1,857 | ||||||
Additional paid-in capital | 1,260,439 | 1,252,034 | ||||||
Retained earnings | 2,925,461 | 2,699,227 | ||||||
Total shareholders’ equity | 4,187,761 | 3,953,118 | ||||||
Total liabilities and shareholders’ equity | $ | 12,764,901 | $ | 11,941,182 | ||||
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
Three months ended March 31, | ||||||||
In thousands, except per share data | 2014 | 2013 | ||||||
Revenues | ||||||||
Crude oil and natural gas sales | $ | 972,147 | $ | 756,217 | ||||
Crude oil and natural gas sales to affiliates | 30,186 | 19,714 | ||||||
Loss on derivative instruments, net | (39,674 | ) | (84,831 | ) | ||||
Crude oil and natural gas service operations | 9,836 | 11,543 | ||||||
Total revenues | 972,495 | 702,643 | ||||||
Operating costs and expenses | ||||||||
Production expenses | 75,976 | 61,318 | ||||||
Production and other expenses to affiliates | 910 | 486 | ||||||
Production taxes and other expenses | 78,302 | 64,842 | ||||||
Exploration expenses | 4,813 | 9,814 | ||||||
Crude oil and natural gas service operations | 8,074 | 8,597 | ||||||
Depreciation, depletion, amortization and accretion | 272,861 | 213,678 | ||||||
Property impairments | 58,208 | 40,081 | ||||||
General and administrative expenses | 43,536 | 33,817 | ||||||
(Gain) loss on sale of assets, net | 8,498 | (136 | ) | |||||
Total operating costs and expenses | 551,178 | 432,497 | ||||||
Income from operations | 421,317 | 270,146 | ||||||
Other income (expense): | ||||||||
Interest expense | (62,975 | ) | (47,475 | ) | ||||
Other | 759 | 546 | ||||||
(62,216 | ) | (46,929 | ) | |||||
Income before income taxes | 359,101 | 223,217 | ||||||
Provision for income taxes | 132,867 | 82,590 | ||||||
Net income | $ | 226,234 | $ | 140,627 | ||||
Basic net income per share | $ | 1.23 | $ | 0.76 | ||||
Diluted net income per share | $ | 1.22 | $ | 0.76 | ||||
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
In thousands, except share data | Shares outstanding | Common stock | Additional paid-in capital | Retained earnings | Total shareholders’ equity | ||||||||||||||
Balance at December 31, 2013 | 185,658,659 | $ | 1,857 | $ | 1,252,034 | $ | 2,699,227 | $ | 3,953,118 | ||||||||||
Net income (unaudited) | — | — | — | 226,234 | 226,234 | ||||||||||||||
Stock-based compensation (unaudited) | — | — | 11,035 | — | 11,035 | ||||||||||||||
Restricted stock: | |||||||||||||||||||
Granted (unaudited) | 465,019 | 4 | — | — | 4 | ||||||||||||||
Repurchased and canceled (unaudited) | (23,221 | ) | — | (2,630 | ) | — | (2,630 | ) | |||||||||||
Forfeited (unaudited) | (20,370 | ) | — | — | — | — | |||||||||||||
Balance at March 31, 2014 (unaudited) | 186,080,087 | $ | 1,861 | $ | 1,260,439 | $ | 2,925,461 | $ | 4,187,761 | ||||||||||
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
Three months ended March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 226,234 | $ | 140,627 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation, depletion, amortization and accretion | 281,115 | 215,464 | ||||||
Property impairments | 58,208 | 40,081 | ||||||
Non-cash loss on derivatives, net | 6,410 | 78,021 | ||||||
Stock-based compensation | 11,039 | 9,242 | ||||||
Provision for deferred income taxes | 131,315 | 82,590 | ||||||
Dry hole costs | — | 2,261 | ||||||
(Gain) loss on sale of assets, net | 8,498 | (136 | ) | |||||
Other, net | 1,754 | 1,390 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (53,857 | ) | (78,118 | ) | ||||
Inventories | (17,669 | ) | (14,995 | ) | ||||
Prepaid expenses and other | (525 | ) | (984 | ) | ||||
Accounts payable trade | 13,854 | 5,068 | ||||||
Revenues and royalties payable | 34,623 | (69 | ) | |||||
Accrued liabilities and other | (9,191 | ) | (22,340 | ) | ||||
Other noncurrent assets and liabilities | (1,146 | ) | 9 | |||||
Net cash provided by operating activities | 690,662 | 458,111 | ||||||
Cash flows from investing activities | ||||||||
Exploration and development | (993,682 | ) | (857,523 | ) | ||||
Purchase of producing crude oil and natural gas properties | (30,278 | ) | (3,332 | ) | ||||
Purchase of other property and equipment | (30,953 | ) | (12,649 | ) | ||||
Proceeds from sale of assets | 35,433 | 351 | ||||||
Net cash used in investing activities | (1,019,480 | ) | (873,153 | ) | ||||
Cash flows from financing activities | ||||||||
Credit facility borrowings | 525,000 | 440,000 | ||||||
Repayment of credit facility | (170,000 | ) | — | |||||
Repayment of other debt | (499 | ) | (485 | ) | ||||
Debt issuance costs | — | (168 | ) | |||||
Repurchase of equity grants | (2,630 | ) | (1,488 | ) | ||||
Net cash provided by financing activities | 351,871 | 437,859 | ||||||
Net change in cash and cash equivalents | 23,053 | 22,817 | ||||||
Cash and cash equivalents at beginning of period | 28,482 | 35,729 | ||||||
Cash and cash equivalents at end of period | $ | 51,535 | $ | 58,546 | ||||
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
Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company'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 various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma areas of 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 74% of the Company’s crude oil and natural gas production and approximately 82% of its crude oil and natural gas revenues for the three months ended March 31, 2014. The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the three months ended March 31, 2014, crude oil accounted for approximately 70% of the Company’s total production and approximately 82% 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 the Company and its subsidiaries, all of which are 100% owned, 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, 2013 (“2013 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.
The condensed consolidated financial statements as of March 31, 2014 and for the three month periods ended March 31, 2014 and 2013 are unaudited. The condensed consolidated balance sheet as of December 31, 2013 was derived from the audited balance sheet included in the 2013 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 periods. Actual results may 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 an entire year.
Inventories
Inventories are stated at the lower of cost or market and consist of the following:
In thousands | March 31, 2014 | December 31, 2013 | ||||||
Tubular goods and equipment | $ | 11,182 | $ | 11,139 | ||||
Crude oil | 60,927 | 43,301 | ||||||
Total | $ | 72,109 | $ | 54,440 | ||||
5
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 | March 31, 2014 | December 31, 2013 | ||||
Crude oil line fill and tank requirements | 501 | 370 | ||||
Temporarily stored crude oil | 607 | 344 | ||||
Total | 1,108 | 714 | ||||
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, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share for the three months ended March 31, 2014 and 2013.
Three months ended March 31, | ||||||||
In thousands, except per share data | 2014 | 2013 | ||||||
Income (numerator): | ||||||||
Net income - basic and diluted | $ | 226,234 | $ | 140,627 | ||||
Weighted average shares (denominator): | ||||||||
Weighted average shares - basic | 184,329 | 183,999 | ||||||
Non-vested restricted stock | 699 | 657 | ||||||
Weighted average shares - diluted | 185,028 | 184,656 | ||||||
Net income per share: | ||||||||
Basic | $ | 1.23 | $ | 0.76 | ||||
Diluted | $ | 1.22 | $ | 0.76 | ||||
Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation. In the prior year, the Company presented charges related to natural gas transportation and processing under the caption “Production taxes and other expenses” or “Production and other expenses to affiliates” in the unaudited condensed consolidated statements of income. Such charges, which totaled $7.6 million for the three months ended March 31, 2013 including transactions with an affiliate totaling $1.2 million, have been reclassified to be netted within “Crude oil and natural gas sales” or "Crude oil and natural gas sales to affiliates", as applicable, in order to conform to the current year presentation. The reclassification had no impact on previously reported operating income, net income, current assets, total assets, current liabilities, total liabilities, stockholders' equity 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.
Three months ended March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Supplemental cash flow information: | ||||||||
Cash paid for interest | $ | 52,194 | $ | 53,169 | ||||
Cash paid for income taxes | — | 11,049 | ||||||
Cash received for income tax refunds | (5 | ) | (8 | ) | ||||
Non-cash investing activities: | ||||||||
Increase in accrued capital expenditures | 47,508 | 42,214 | ||||||
Asset retirement obligation additions and revisions, net | 1,270 | 2,227 | ||||||
6
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 4. Derivative Instruments
The Company recognizes 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 changes in fair value in the unaudited condensed consolidated statements of income under the caption “Loss on derivative instruments, net.”
The Company has utilized swap and collar derivative contracts to economically 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 March 31, 2014, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below.
Crude Oil - NYMEX WTI | Swaps Weighted Average Price | ||||||
Period and Type of Contract | Bbls | ||||||
April 2014 - December 2014 | |||||||
Swaps - WTI | 9,968,750 | $ | 96.22 | ||||
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 | ||||||||||||||||||||
April 2014 - December 2014 | |||||||||||||||||||||||
Swaps - ICE Brent | 13,293,000 | $ | 103.24 | ||||||||||||||||||||
Collars - ICE Brent | 1,650,000 | $90.00 - $95.00 | $ | 90.83 | $104.70 - $108.85 | $ | 107.13 | ||||||||||||||||
January 2015 - December 2015 | |||||||||||||||||||||||
Swaps - ICE Brent | 17,337,500 | $ | 100.67 | ||||||||||||||||||||
Collars - ICE Brent | 730,000 | $ | 95.00 | $ | 95.00 | $ | 107.40 | $ | 107.40 | ||||||||||||||
7
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Collars | |||||||||||||||||||
Natural Gas - NYMEX Henry Hub | Swaps Weighted Average Price | Floors | Ceilings | ||||||||||||||||
Weighted Average Price | Weighted Average Price | ||||||||||||||||||
Period and Type of Contract | MMBtus | Range | Range | ||||||||||||||||
April 2014 - December 2014 | |||||||||||||||||||
Swaps - Henry Hub | 88,485,000 | $ | 4.21 | ||||||||||||||||
January 2015 - December 2015 | |||||||||||||||||||
Swaps - Henry Hub | 24,500,000 | $ | 4.27 | ||||||||||||||||
Collars - Henry Hub | 29,200,000 | $3.50 - $3.75 | $ | 3.69 | $4.89 - $5.48 | $ | 5.04 | ||||||||||||
January 2016 - December 2016 | |||||||||||||||||||
Swaps - Henry Hub | 4,550,000 | $ | 4.27 | ||||||||||||||||
Derivative gains and losses
The following table presents cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
Three months ended March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Cash received (paid) on derivatives: | ||||||||
Crude oil fixed price swaps | $ | (22,523 | ) | $ | (9,593 | ) | ||
Crude oil collars | (584 | ) | 125 | |||||
Natural gas fixed price swaps | (10,157 | ) | 2,658 | |||||
Cash paid on derivatives, net | (33,264 | ) | (6,810 | ) | ||||
Non-cash gain (loss) on derivatives: | ||||||||
Crude oil fixed price swaps | 13,690 | (33,364 | ) | |||||
Crude oil collars | 5,283 | (13,762 | ) | |||||
Natural gas fixed price swaps | (25,401 | ) | (30,895 | ) | ||||
Natural gas collars | 18 | — | ||||||
Non-cash loss on derivatives, net | (6,410 | ) | (78,021 | ) | ||||
Loss on derivative instruments, net | $ | (39,674 | ) | $ | (84,831 | ) | ||
Balance sheet offsetting of derivative assets and liabilities
All of the Company’s derivative contracts are recorded at fair value in the condensed consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative 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.
8
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
The following table presents 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.
In thousands | March 31, 2014 | December 31, 2013 | ||||||
Commodity derivative assets: | ||||||||
Gross amounts of recognized assets | $ | 3,682 | $ | 4,213 | ||||
Gross amounts offset on balance sheet | (230 | ) | (597 | ) | ||||
Net amounts of assets on balance sheet | $ | 3,452 | $ | 3,616 | ||||
Commodity derivative liabilities: | ||||||||
Gross amounts of recognized liabilities | $ | (121,287 | ) | $ | (125,709 | ) | ||
Gross amounts offset on balance sheet | 16,677 | 27,345 | ||||||
Net amounts of liabilities on balance sheet | $ | (104,610 | ) | $ | (98,364 | ) | ||
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.
In thousands | March 31, 2014 | December 31, 2013 | ||||||
Derivative assets | $ | 799 | $ | 3,616 | ||||
Noncurrent derivative assets | 2,653 | — | ||||||
Net amounts of assets on balance sheet | 3,452 | 3,616 | ||||||
Derivative liabilities | (98,493 | ) | (90,535 | ) | ||||
Noncurrent derivative liabilities | (6,117 | ) | (7,829 | ) | ||||
Net amounts of liabilities on balance sheet | (104,610 | ) | (98,364 | ) | ||||
Total derivative liabilities, net | $ | (101,158 | ) | $ | (94,748 | ) | ||
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.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company's derivative instruments are reported at fair value on a recurring basis. 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
9
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
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 of fair value 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 March 31, 2014 and December 31, 2013.
Fair value measurements at March 31, 2014 using: | ||||||||||||||||
In thousands | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Description | ||||||||||||||||
Derivative assets (liabilities): | ||||||||||||||||
Fixed price swaps | $ | — | $ | (96,604 | ) | $ | — | $ | (96,604 | ) | ||||||
Collars | — | (4,554 | ) | — | (4,554 | ) | ||||||||||
Total | $ | — | $ | (101,158 | ) | $ | — | $ | (101,158 | ) | ||||||
Fair value measurements at December 31, 2013 using: | ||||||||||||||||
In thousands | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Description | ||||||||||||||||
Derivative assets (liabilities): | ||||||||||||||||
Fixed price swaps | $ | — | $ | (84,893 | ) | $ | — | $ | (84,893 | ) | ||||||
Collars | — | (9,855 | ) | — | (9,855 | ) | ||||||||||
Total | $ | — | $ | (94,748 | ) | $ | — | $ | (94,748 | ) | ||||||
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 2018 (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% | |
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.
10
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
During the three months ended March 31, 2014, 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 $3.8 million for the three months ended March 31, 2014, which reflect fair value adjustments made for certain properties in a non-core area of our South region driven by uneconomic well results. The impaired properties were written down to their estimated fair value totaling approximately $1.1 million. There were no impairments of proved properties during the three months ended March 31, 2013.
Certain unproved crude oil and natural gas properties were impaired during the three months ended March 31, 2014 and 2013, 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 March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Proved property impairments | $ | 3,762 | $ | — | ||||
Unproved property impairments | 54,446 | 40,081 | ||||||
Total | $ | 58,208 | $ | 40,081 | ||||
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.
March 31, 2014 | December 31, 2013 | |||||||||||||||
In thousands | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Debt: | ||||||||||||||||
Credit facility | $ | 630,000 | $ | 630,000 | $ | 275,000 | $ | 275,000 | ||||||||
Note payable | 17,971 | 16,174 | 18,470 | 16,500 | ||||||||||||
8 1/4% Senior Notes due 2019 | 298,363 | 324,000 | 298,305 | 327,800 | ||||||||||||
7 3/8% Senior Notes due 2020 | 198,732 | 224,640 | 198,695 | 223,700 | ||||||||||||
7 1/8% Senior Notes due 2021 | 400,000 | 452,120 | 400,000 | 450,300 | ||||||||||||
5% Senior Notes due 2022 | 2,024,777 | 2,105,000 | 2,025,362 | 2,063,300 | ||||||||||||
4 1/2% Senior Notes due 2023 | 1,500,000 | 1,555,650 | 1,500,000 | 1,519,400 | ||||||||||||
Total debt | $ | 5,069,843 | $ | 5,307,584 | $ | 4,715,832 | $ | 4,876,000 | ||||||||
The fair value of credit facility borrowings approximates 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.
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.
11
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 6. Long-Term Debt
Long-term debt consists of the following at March 31, 2014 and December 31, 2013:
In thousands | March 31, 2014 | December 31, 2013 | ||||||
Credit facility | $ | 630,000 | $ | 275,000 | ||||
Note payable | 17,971 | 18,470 | ||||||
8 1/4% Senior Notes due 2019 (1) | 298,363 | 298,305 | ||||||
7 3/8% Senior Notes due 2020 (2) | 198,732 | 198,695 | ||||||
7 1/8% Senior Notes due 2021 (3) | 400,000 | 400,000 | ||||||
5% Senior Notes due 2022 (4) | 2,024,777 | 2,025,362 | ||||||
4 1/2% Senior Notes due 2023 (3) | 1,500,000 | 1,500,000 | ||||||
Total debt | $ | 5,069,843 | $ | 4,715,832 | ||||
Less: Current portion of long-term debt | (2,029 | ) | (2,011 | ) | ||||
Long-term debt, net of current portion | $ | 5,067,814 | $ | 4,713,821 | ||||
(1) | The carrying amount is net of unamortized discounts of $1.6 million and $1.7 million at March 31, 2014 and December 31, 2013, respectively. |
(2) | The carrying amount is net of unamortized discounts of $1.3 million and $1.3 million at March 31, 2014 and December 31, 2013, respectively. |
(3) | These notes were sold at par and are recorded at 100% of face value. |
(4) | The carrying amount includes an unamortized premium of $24.8 million and $25.4 million at March 31, 2014 and December 31, 2013, respectively. |
Credit Facility
The Company has an unsecured credit facility, maturing on July 1, 2015, with aggregate lender commitments totaling $1.5 billion. The Company had $630 million and $275 million of outstanding borrowings on its credit facility at March 31, 2014 and December 31, 2013, respectively. 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 of 150 basis points, or the lead bank’s reference rate (prime) plus a margin of 50 basis points. The Company had approximately $868 million of unused commitments (after considering outstanding borrowings and letters of credit) under its credit facility at March 31, 2014 and incurs commitment fees of 0.25% 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. 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 March 31, 2014.
12
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Senior Notes
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 March 31, 2014.
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 | — | |||||
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) | — | — | — | March 15, 2015 | — | |||||
(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 or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption. |
(3) | At any time prior to this date, the Company may redeem up to 35% of the principal amount of its 2022 Notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption price specified in the indenture for the 2022 Notes plus any accrued and unpaid interest to the date of redemption. |
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
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. However, given the investment grade credit ratings currently assigned to the Company's senior unsecured debt, certain of the restrictive covenants are not currently applicable, including those limiting the Company's ability to incur additional debt, pay dividends, make certain investments, engage in certain affiliate transactions, and sell certain assets, among others. In the event the Company's credit ratings are reduced below BBB- by Standard & Poor's Ratings Services or Baa3 by Moody’s Investor Services, Inc. or collateral is reinstated under the credit facility, such covenants would be restored. The indenture governing the 2023 Notes is less restrictive and contains covenants that, among others, limit the Company's ability to create liens securing certain indebtedness and consolidate, merge or transfer certain assets.
The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at March 31, 2014. 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 subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes.
Note Payable
In February 2012, 20 Broadway Associates LLC, a 100% 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 March 31, 2014.
Note 7. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of March 31, 2014. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.
Drilling commitments – As of March 31, 2014, the Company had drilling rig contracts with various terms extending through January 2017. 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 March 31, 2014 total approximately $149 million, of which $82 million is expected to be incurred in the remainder of 2014, $47 million in 2015, $19 million in 2016, and $1 million in 2017.
13
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have varying terms extending as far as 2024, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of March 31, 2014 under the operational pipeline transportation arrangements amount to approximately $96 million, of which $15 million is expected to be incurred in the remainder of 2014, $19 million in 2015, $16 million in 2016, $11 million in 2017, $6 million in 2018, and $29 million thereafter.
Further, the Company is a party to additional 5-year firm transportation commitments for future crude oil pipeline projects being constructed or considered for development that are not yet operational. Such projects require the granting of regulatory approvals or otherwise require additional construction efforts by counterparties before being completed. Future commitments under the non-operational arrangements total approximately $1.0 billion at March 31, 2014, which includes approximately $96 million subject to a joint tariff arrangement between an unaffiliated party and an affiliate controlled by the Company's 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 exact 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, operators have indicated that certain pipeline projects may become operational in the second half of 2014, which would obligate the Company for transportation charges totaling $36 million in 2014, $143 million annually in years 2015 through 2018, and $106 million in 2019 associated with those projects.
The Company’s pipeline 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.
Cost sharing commitment – The Company has entered into an arrangement to share certain costs associated with a local utility company's construction and installation of electrical infrastructure that will provide service to parts of North Dakota where the Company operates. This arrangement extends through January 2016 and requires the Company to make scheduled periodic payments based on the projected total cost of the project and the progress of construction. Future commitments under the arrangement as of March 31, 2014 total approximately $20 million, of which $10 million is expected to be incurred in the remainder of 2014, $8 million in 2015, and $2 million in 2016.
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 which may increase with the passage of time, 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 including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and other 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 March 31, 2014 and December 31, 2013, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $2.9 million and $1.7 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.
14
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
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 March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Non-cash equity compensation | $ | 11,039 | $ | 9,242 | ||||
In May 2013, the Company adopted the 2013 Plan and reserved a maximum of 9,840,036 shares of common stock that may be issued pursuant to the plan. 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. As of March 31, 2014, the Company had a maximum of 9,392,561 shares of restricted stock available to grant to officers, directors and select employees under the 2013 Plan.
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 shares outstanding for the three months ended March 31, 2014 is presented below:
Number of non-vested shares | Weighted average grant-date fair value | ||||||
Non-vested restricted shares outstanding at December 31, 2013 | 1,357,156 | $ | 74.99 | ||||
Granted | 465,019 | 118.18 | |||||
Vested | (71,432 | ) | 77.41 | ||||
Forfeited | (20,370 | ) | 76.29 | ||||
Non-vested restricted shares outstanding at March 31, 2014 | 1,730,373 | $ | 86.48 | ||||
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 three months ended March 31, 2014 at the vesting date was approximately $8.1 million. As of March 31, 2014, there was approximately $97 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ratably over a weighted average period of 1.7 years.
Note 9. Property Dispositions
During the three months ended March 31, 2014, the Company sold certain non-strategic properties in Colorado, Wyoming, South Dakota and North Dakota to third parties for proceeds totaling $35.4 million. In connection with the transactions, the Company recognized pre-tax losses totaling $8.5 million. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.
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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, 2013. 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 in 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, 2013, 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 various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma areas of Oklahoma. 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 74% of our crude oil and natural gas production and approximately 82% of our crude oil and natural gas revenues for the three months ended March 31, 2014.
We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas. 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 three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture stimulation) and enhanced recovery technologies provide the means to economically develop and produce crude oil and natural gas reserves from unconventional formations. We expect growth in our revenues and operating income will primarily depend on commodity prices and our ability to increase our reserves and related crude oil and natural gas production.
2014 Highlights
Production, revenues and operating cash flows
For the first quarter of 2014, our crude oil and natural gas production averaged 152,471 Boe per day, representing a 6% increase over average daily production of 144,254 Boe per day for the fourth quarter of 2013 and a 25% increase over average daily production of 121,532 Boe per day for the first quarter of 2013. Crude oil represented 70% of our total production for the three months ended March 31, 2014 compared to 71% for the three months ended March 31, 2013.
The increase in 2014 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 83,725 Boe per day for the three months ended March 31, 2014, a 4% increase over the fourth quarter of 2013 and 24% higher than the first quarter of 2013. Production in the emerging SCOOP play averaged 29,363 Boe per day for the three months ended March 31, 2014, an increase of 24% over the fourth quarter of 2013 and 106% higher than the first quarter of 2013.
Crude oil and natural gas revenues for the first quarter of 2014 increased 29% to $1.0 billion due to a 23% increase in sales volumes along with a 5% increase in realized commodity prices when compared to the first quarter of 2013. Crude oil represented 82% of our total crude oil and natural gas revenues for the three months ended March 31, 2014 compared to 89% for the three months ended March 31, 2013. The decreased percentage of crude oil revenues resulted from a significant increase in SCOOP revenues as a percentage of our total revenues over the past year. Our properties in SCOOP produce a higher concentration of liquids-rich natural gas compared to certain other operating areas such as the Bakken.
Cash flows from operating activities for the three months ended March 31, 2014 were $690.7 million, a 51% increase from $458.1 million provided by our operating activities during the comparable 2013 period. The increased operating cash flows in 2014 were primarily due to higher crude oil and natural gas revenues driven by higher sales volumes and realized commodity prices, partially offset by an increase in cash losses on matured derivatives and higher production expenses,
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production taxes, general and administrative expenses, interest expense and other expenses associated with the growth of our operations over the past year.
Capital expenditures
Our capital expenditures budget for 2014 is $4.05 billion, excluding acquisitions. For the three months ended March 31, 2014, we invested approximately $1.0 billion in our capital program, excluding $66.4 million of unbudgeted acquisitions and including $2.9 million of seismic costs and $47.5 million of capital costs associated with increased accruals for capital expenditures. Our 2014 capital program is focused primarily on increased exploration and development in the Bakken field and the SCOOP play.
Financial and operating highlights
We use a variety of financial and operating measures to assess our performance. Among these measures are:
• | Volumes of crude oil and natural gas produced, |
• | Crude oil and natural gas prices realized, |
• | Per unit operating and administrative costs, and |
• | EBITDAX (a non-GAAP financial measure). |
The following table contains financial and operating highlights for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended March 31, | ||||||||
2014 | 2013 | |||||||
Average daily production: | ||||||||
Crude oil (Bbl per day) | 106,398 | 86,071 | ||||||
Natural gas (Mcf per day) | 276,439 | 212,766 | ||||||
Crude oil equivalents (Boe per day) | 152,471 | 121,532 | ||||||
Average sales prices: | ||||||||
Crude oil ($/Bbl) | $ | 89.73 | $ | 89.99 | ||||
Natural gas ($/Mcf) | $ | 7.06 | $ | 4.59 | ||||
Crude oil equivalents ($/Boe) | $ | 75.03 | $ | 71.61 | ||||
Crude oil sales price differential to NYMEX ($/Bbl) | $ | (8.98 | ) | $ | (4.29 | ) | ||
Natural gas sales price premium to NYMEX ($/Mcf) | $ | 2.14 | $ | 1.25 | ||||
Production expenses ($/Boe) | $ | 5.76 | $ | 5.70 | ||||
Production taxes (% of oil and gas revenues) | 7.7 | % | 8.3 | % | ||||
DD&A ($/Boe) | $ | 20.43 | $ | 19.72 | ||||
General and administrative expenses ($/Boe) | $ | 2.43 | $ | 2.26 | ||||
Non-cash equity compensation ($/Boe) | $ | 0.83 | $ | 0.85 | ||||
Net income (in thousands) | $ | 226,234 | $ | 140,627 | ||||
Diluted net income per share | $ | 1.22 | $ | 0.76 | ||||
EBITDAX (in thousands) (1) | $ | 775,407 | $ | 621,528 | ||||
(1) | 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. |
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Three months ended March 31, 2014 compared to the three months ended March 31, 2013
Results of Operations
The following table presents selected financial and operating information for the periods presented.
Three months ended March 31, | ||||||||
In thousands, except sales price data | 2014 | 2013 | ||||||
Crude oil and natural gas sales | $ | 1,002,333 | $ | 775,931 | ||||
Loss on derivative instruments, net (1) | (39,674 | ) | (84,831 | ) | ||||
Crude oil and natural gas service operations | 9,836 | 11,543 | ||||||
Total revenues | 972,495 | 702,643 | ||||||
Operating costs and expenses | (551,178 | ) | (432,497 | ) | ||||
Other expenses, net | (62,216 | ) | (46,929 | ) | ||||
Income before income taxes | 359,101 | 223,217 | ||||||
Provision for income taxes | (132,867 | ) | (82,590 | ) | ||||
Net income | $ | 226,234 | $ | 140,627 | ||||
Production volumes: | ||||||||
Crude oil (MBbl) (2) | 9,576 | 7,746 | ||||||
Natural gas (MMcf) | 24,879 | 19,149 | ||||||
Crude oil equivalents (MBoe) | 13,722 | 10,938 | ||||||
Sales volumes: | ||||||||
Crude oil (MBbl) (2) | 9,213 | 7,645 | ||||||
Natural gas (MMcf) | 24,879 | 19,149 | ||||||
Crude oil equivalents (MBoe) | 13,359 | 10,836 | ||||||
Average sales prices: | ||||||||
Crude oil ($/Bbl) | $ | 89.73 | $ | 89.99 | ||||
Natural gas ($/Mcf) | 7.06 | 4.59 | ||||||
Crude oil equivalents ($/Boe) | 75.03 | 71.61 | ||||||
(1) | Amounts include non-cash mark-to-market losses on derivatives of $6.4 million and $78.0 million for the three months ended March 31, 2014 and 2013, 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 363 MBbls less than crude oil production for the three months ended March 31, 2014 and 101 MBbls less than crude oil production for the three months ended March 31, 2013. |
Production
The following tables reflect our production by product and region for the periods presented.
Three months ended March 31, | Volume increase | Volume percent increase | ||||||||||||||||
2014 | 2013 | |||||||||||||||||
Volume | Percent | Volume | Percent | |||||||||||||||
Crude oil (MBbl) | 9,576 | 70 | % | 7,746 | 71 | % | 1,830 | 24 | % | |||||||||
Natural gas (MMcf) | 24,879 | 30 | % | 19,149 | 29 | % | 5,730 | 30 | % | |||||||||
Total (MBoe) | 13,722 | 100 | % | 10,938 | 100 | % | 2,784 | 25 | % | |||||||||
Three months ended March 31, | Volume increase | Volume percent increase | ||||||||||||||||
2014 | 2013 | |||||||||||||||||
MBoe | Percent | MBoe | Percent | |||||||||||||||
North Region | 10,118 | 74 | % | 8,392 | 77 | % | 1,726 | 21 | % | |||||||||
South Region | 3,604 | 26 | % | 2,546 | 23 | % | 1,058 | 42 | % | |||||||||
Total | 13,722 | 100 | % | 10,938 | 100 | % | 2,784 | 25 | % | |||||||||
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Crude oil production volumes increased 1,830 MBbls, or 24%, for the three months ended March 31, 2014 compared to the three months ended March 31, 2013. Production increases in the Bakken field and SCOOP play contributed incremental production volumes in 2014 of 1,933 MBbls, a 31% increase over production in these areas for the first quarter of 2013. 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 in production from our properties in the Red River units and Northwest Cana totaling 99 MBbls, or 7%, compared to the prior year first quarter due to a combination of natural declines in production and reduced drilling activity in those areas.
Natural gas production volumes increased 5,730 MMcf, or 30%, during the three months ended March 31, 2014 compared to the same period in 2013. Natural gas production in the Bakken field increased 1,365 MMcf, or 23%, for the three months ended March 31, 2014 compared to the same period in 2013 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 6,287 MMcf, or 115%, due to additional wells being completed and producing in the three months ended March 31, 2014 compared to the same period in 2013. These increases were partially offset by decreases in production volumes totaling 1,892 MMcf, or 26%, from our properties in Northwest Cana, Arkoma Woodford, and non-core areas in our North and South regions due to a combination of natural declines in production and reduced drilling activity.
Revenues
Our total revenues consist of sales of crude oil and natural gas, gains and losses resulting from 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 March 31, 2014 were $1,002.3 million, a 29% increase from sales of $775.9 million for the same period in 2013. Our sales volumes increased 2,523 MBoe, or 23%, over the comparable period in 2013 primarily due to the success of our drilling programs in the Bakken field and SCOOP play. An increase in crude oil pipeline line fill requirements and the temporary impact of adverse weather on railcar availability to transport our crude oil to market increased crude oil inventory during the first quarter of 2014, causing crude oil sales volumes to be lower than crude oil production by 363 MBbls. We anticipate a further increase in crude oil line fill requirements during the second and third quarters of 2014 as new pipelines are put into service for which we have contracted firm capacity.
Our realized sales price per Boe increased $3.42 to $75.03 for the three months ended March 31, 2014 from $71.61 for the three months ended March 31, 2013. This increase primarily reflects higher natural gas prices realized in connection with improved market prices for natural gas and natural gas liquids.
The premium of our realized natural gas sales price per Mcf over NYMEX Henry Hub calendar month average natural gas prices for the first quarter of 2014 was $2.14 compared to $1.25 for the first quarter of 2013 and $1.51 for the fourth quarter of 2013. The improved differential reflects an increase in the production and sale of liquids-rich natural gas from our Bakken and SCOOP properties coupled with improved market prices for natural gas liquids in the 2014 first quarter.
The differential between NYMEX West Texas Intermediate calendar month average crude oil prices and our realized crude oil sales price per barrel for the first quarter of 2014 was $8.98 compared to $4.29 for the first quarter of 2013 and $13.05 for the fourth quarter of 2013. We expect volatility in crude oil differentials to continue.
Derivatives. We have entered into a number of derivative contracts, 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 changes in fair value in the unaudited condensed consolidated statements of income under the caption “Loss on derivative instruments, net”, which is a component of total revenues.
Changes in commodity prices during the first quarter of 2014 had a negative impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $39.7 million for the three months ended March 31, 2014. 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.
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The following table presents the impact on total revenues related to cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
Three months ended March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Cash received (paid) on derivatives: | ||||||||
Crude oil derivatives | $ | (23,107 | ) | $ | (9,468 | ) | ||
Natural gas derivatives | (10,157 | ) | 2,658 | |||||
Cash paid on derivatives, net | (33,264 | ) | (6,810 | ) | ||||
Non-cash gain (loss) on derivatives: | ||||||||
Crude oil derivatives | 18,973 | (47,126 | ) | |||||
Natural gas derivatives | (25,383 | ) | (30,895 | ) | ||||
Non-cash loss on derivatives, net | (6,410 | ) | (78,021 | ) | ||||
Loss on derivative instruments, net | $ | (39,674 | ) | $ | (84,831 | ) | ||
The non-cash mark-to-market gains and losses reflected above at March 31, 2014 relate to derivative instruments with various terms that are scheduled to be realized over the period from April 2014 to December 2016. Over this period, actual derivative settlements may differ significantly, either positively or negatively, from the mark-to-market valuation at March 31, 2014.
Operating Costs and Expenses
Production Expenses and Production Taxes and Other Expenses. Production expenses increased 24% to $76.9 million for the three months ended March 31, 2014 from $61.8 million for the three months ended March 31, 2013. This increase was primarily the result of an increase in the number of producing wells. Production expense per Boe was $5.76 for the three months ended March 31, 2014 compared to $5.70 per Boe for the three months ended March 31, 2013.
Production taxes and other expenses increased $13.5 million, or 21%, to $78.3 million for the three months ended March 31, 2014 compared to $64.8 million for the three months ended March 31, 2013 primarily as a result of higher crude oil and natural gas revenues resulting from increased sales volumes and higher realized commodity prices. Production taxes as a percentage of crude oil and natural gas revenues were 7.7% for the three months ended March 31, 2014 compared to 8.3% for the three months ended March 31, 2013. The decrease was due to significant growth over the past year in our SCOOP operations and resulting increase in taxable revenues coming from Oklahoma, which has lower production tax rates compared to our other key operating areas. 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.
Exploration Expenses. Exploration expenses consist primarily of dry hole costs and geological and geophysical costs that are expensed as incurred. The following table shows the components of exploration expenses for the periods indicated.
Three months ended March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Geological and geophysical costs | $ | 4,813 | $ | 7,553 | ||||
Dry hole costs | — | 2,261 | ||||||
Exploration expenses | $ | 4,813 | $ | 9,814 | ||||
Geological and geophysical costs decreased $2.7 million for the three months ended March 31, 2014 due to changes in the timing and amount of costs incurred between periods. No dry hole costs were incurred during the three months ended March 31, 2014.
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Depreciation, Depletion, Amortization and Accretion (“DD&A”). Total DD&A increased $59.2 million, or 28%, to $272.9 million for the first quarter of 2014 compared to $213.7 million for the first quarter of 2013 primarily due to a 23% increase in sales volumes. The following table shows the components of our DD&A on a unit of sales basis.
Three months ended March 31, | ||||||||
$/Boe | 2014 | 2013 | ||||||
Crude oil and natural gas | $ | 20.08 | $ | 19.43 | ||||
Other equipment | 0.29 | 0.23 | ||||||
Asset retirement obligation accretion | 0.06 | 0.06 | ||||||
Depreciation, depletion, amortization and accretion | $ | 20.43 | $ | 19.72 | ||||
The increase in DD&A per Boe for the first quarter of 2014 primarily resulted from changes in the operational timing of pad drilling and resulting mix of well completions over the past year.
Property Impairments. Property impairments increased in the three months ended March 31, 2014 by $18.1 million to $58.2 million compared to $40.1 million for the three months ended March 31, 2013.
Impairments of non-producing properties increased $14.3 million for the three months ended March 31, 2014 to $54.4 million compared to $40.1 million for the three months ended March 31, 2013. The increase primarily 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.
Impairment provisions for proved properties totaled $3.8 million for the three months ended March 31, 2014, with no proved property impairments being recognized for the three months ended March 31, 2013. Proved property impairments in the 2014 first quarter primarily reflect fair value adjustments made for certain properties in a non-core area of our South region driven by uneconomic well results.
General and Administrative Expenses. General and administrative expenses (“G&A”) increased $9.7 million, or 29%, to $43.5 million for the three months ended March 31, 2014 from $33.8 million for the comparable period in 2013. G&A expenses include non-cash charges for equity compensation of $11.0 million and $9.2 million for the three months ended March 31, 2014 and 2013, respectively. The increase in equity compensation in 2014 resulted from a higher value of restricted stock grants being made in 2013 and 2014 due to employee growth, which resulted in increased expense recognition in the first quarter of 2014 compared to the first quarter of 2013.
G&A expenses other than equity compensation increased $7.9 million, or 32%, for the three months ended March 31, 2014 compared to the same period in 2013. The increase was primarily due to an increase in personnel costs and office-related expenses associated with our growth. Over the past year, our Company has grown from having 769 total employees in March 2013 to 986 total employees in March 2014, a 28% increase.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.
Three months ended March 31, | ||||||||
$/Boe | 2014 | 2013 | ||||||
General and administrative expenses | $ | 2.43 | $ | 2.20 | ||||
Non-cash equity compensation | 0.83 | 0.85 | ||||||
Corporate relocation expenses | — | 0.06 | ||||||
Total general and administrative expenses | $ | 3.26 | $ | 3.11 | ||||
Interest Expense. Interest expense increased $15.5 million, or 33%, to $63.0 million for the three months ended March 31, 2014 compared to $47.5 million for the three months ended March 31, 2013 due to an increase in our weighted average outstanding long-term debt obligations. Our weighted average outstanding long-term debt balance for the first quarter of 2014 was approximately $4.9 billion with a weighted average interest rate of 5.0% compared to a weighted average outstanding long-term debt balance of $3.7 billion and a weighted average interest rate of 4.9% for the comparable period in 2013. The increase in outstanding debt primarily resulted from the issuance of $1.5 billion of 4 1/2% Senior Notes due 2023 in April 2013, partially offset by lower outstanding credit facility borrowings in the first quarter of 2014 compared to the first quarter of 2013.
Our weighted average outstanding credit facility balance amounted to $511.8 million for the first quarter of 2014 compared to $815.9 million for the first quarter of 2013. The weighted average interest rate on our credit facility borrowings was 1.8% for the first quarter of 2014 compared to 1.9% for the same period in 2013. At March 31, 2014, we had $630 million of outstanding borrowings on our credit facility compared to $1.0 billion outstanding at March 31, 2013, which was
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subsequently paid off using a portion of the proceeds from our issuance of the 2023 Notes in April 2013. We had $275 million of outstanding borrowings on our credit facility at December 31, 2013. The increase in credit facility borrowings in the 2014 first quarter resulted from borrowings being incurred to fund our capital program.
Income Taxes. We recorded income tax expense for the three months ended March 31, 2014 of $132.9 million compared to $82.6 million for the three months ended March 31, 2013. We provided for income taxes at a combined federal and state tax rate of approximately 37% for the first quarters of both 2013 and 2014 after taking into account permanent taxable differences.
Liquidity and Capital Resources
Our primary sources of liquidity have been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt and equity securities. As of March 31, 2014, we had $51.5 million of cash and cash equivalents and $868 million of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had $630 million of outstanding borrowings on our credit facility at March 31, 2014. As of May 1, 2014, we had $750 million of outstanding borrowings and approximately $748 million of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit.
Cash Flows
Cash flows from operating activities
Our net cash provided by operating activities was $690.7 million and $458.1 million for the three months ended March 31, 2014 and 2013, respectively. The increase in operating cash flows was primarily due to higher crude oil and natural gas revenues driven by higher sales volumes and realized commodity prices, which were partially offset by an increase in cash losses on matured derivatives and increases in production expenses, production taxes, general and administrative expenses, interest expense and other expenses associated with the growth of our operations over the past year.
Cash flows used in investing activities
During the three months ended March 31, 2014 and 2013, we had cash flows used in investing activities (excluding proceeds from asset sales) of $1,054.9 million and $873.5 million, respectively, related to our capital program, inclusive of dry hole costs and property acquisitions. Cash acquisition capital expenditures totaled $66.4 million and $22.0 million for the three months ended March 31, 2014 and 2013, respectively. Cash capital expenditures excluding acquisitions totaled $988.5 million and $851.5 million for the three months ended March 31, 2014 and 2013, respectively, the increase of which was driven by an increase in drilling activity in 2014.
The use of cash for capital expenditures during the three months ended March 31, 2014 was partially offset by proceeds received from asset dispositions. Proceeds from the sale of assets amounted to $35.4 million in the 2014 first quarter, primarily related to dispositions of properties in the Niobrara play in Colorado and Wyoming in March 2014 for proceeds totaling $30.3 million.
Cash flows from financing activities
Net cash provided by financing activities for the three months ended March 31, 2014 and 2013 was $351.9 million and $437.9 million, respectively, primarily resulting from $355 million and $440 million, respectively, of net borrowings being incurred on our credit facility during those periods to fund a portion of our capital programs.
Future Sources of Financing
Although we cannot provide any assurance, assuming sustained strength in crude oil prices and successful implementation of our business strategy, we believe funds from operating cash flows, our remaining cash balance, and our credit facility, including our ability to increase our borrowing capacity thereunder, should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures, and commitments for the next 12 months. 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.
Based on our planned production growth and derivative contracts we have in place to limit the downside risk of adverse price movements associated with the forecasted sale of future production, we currently anticipate we will be able to generate or obtain funds sufficient to meet our short-term and long-term cash requirements. We intend to finance future capital expenditures primarily through cash flows from operations and through borrowings under our credit facility, but we may also issue debt or equity securities or sell assets. The issuance of additional debt requires a portion of our cash flows from operations
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be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
Credit facility
We have an unsecured credit facility, maturing on July 1, 2015, which has aggregate lender commitments totaling $1.5 billion. We had $630 million of outstanding borrowings and $868 million of borrowing availability (after considering outstanding borrowings and letters of credit) on our credit facility at March 31, 2014. As of May 1, 2014, we had $750 million of outstanding borrowings and $748 million of borrowing availability on our credit facility. The increase in outstanding borrowings subsequent to March 31, 2014 resulted from borrowings incurred to fund a portion of our 2014 capital program.
Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, change material contracts, incur liens and engage in certain other transactions without the prior consent of the lenders. Our credit facility also contains requirements that we 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. We were in compliance with these covenants at March 31, 2014. We do not believe the restrictive covenants are reasonably likely to limit our ability to undertake additional debt or equity financing to a material extent.
We are engaged in discussions with our lenders to replace our credit facility, which is expected to occur during the second quarter of 2014. We expect the new credit facility will provide for increased aggregate commitments and an extended maturity beyond the term of our existing credit facility.
In the future, we may not be able to access adequate funding under our credit facility as a result of (i) a decrease in our credit ratings that triggers a borrowing base requirement, subjecting us to the risk that other events may adversely impact the size of our borrowing base, (ii) a decline in commodity prices, or (iii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations or increase their commitments as required under the credit facility.
If we are unable to access funding on acceptable terms when needed, we may not be able to fully implement our business plans, complete new property acquisitions to replace our reserves, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.
Future Capital Requirements
Senior notes
Our long-term debt includes outstanding senior note obligations totaling $4.4 billion at March 31, 2014. Scheduled maturities of our senior notes begin in October 2019. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. For further information on the maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 6. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements. We were in compliance with our senior note covenants at March 31, 2014 and expect to maintain compliance for at least the next 12 months. We do not believe the restrictive covenants under the senior note indentures will materially limit our ability to undertake additional debt or equity financing.
Two of our 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. Our other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes.
Capital expenditures
We evaluate opportunities to purchase or sell crude oil and natural gas properties and expect to participate as a buyer or seller of properties at various times. We seek acquisitions that utilize our technical expertise or offer opportunities to expand our existing core areas. Acquisition expenditures are not budgeted.
Our capital expenditures budget for 2014 is $4.05 billion excluding acquisitions, which is expected to be allocated as follows:
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In millions | Amount | ||
Exploration and development drilling | $ | 3,540 | |
Land costs | 300 | ||
Capital facilities, workovers and other corporate assets | 180 | ||
Seismic | 30 | ||
Total 2014 capital budget, excluding acquisitions | $ | 4,050 | |
During the three months ended March 31, 2014, we participated in the completion of 213 gross (84.4 net) wells and invested approximately $1,037.0 million in our capital program, excluding $66.4 million of unbudgeted acquisitions and including $2.9 million of seismic costs and $47.5 million of capital costs associated with increased accruals for capital expenditures. Our 2014 year-to-date capital expenditures were allocated as follows:
In millions | Amount | ||
Exploration and development drilling | $ | 902.2 | |
Land costs | 83.5 | ||
Capital facilities, workovers and other corporate assets | 48.4 | ||
Seismic | 2.9 | ||
Capital expenditures, excluding acquisitions | 1,037.0 | ||
Acquisitions of producing properties | 30.3 | ||
Acquisitions of non-producing properties | 36.1 | ||
Total acquisitions | 66.4 | ||
Total capital expenditures | $ | 1,103.4 | |
Our 2014 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.
The actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, access to capital, available cash flows, unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, changes in commodity prices, and regulatory, technological and competitive developments. A decline in commodity prices could cause us to curtail our actual capital expenditures. Conversely, an increase in commodity prices could result in increased capital expenditures. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at competitive terms.
Commitments
Following is a discussion of various future commitments of the Company as of March 31, 2014. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.
Drilling commitments – As of March 31, 2014, we had drilling rig contracts with various terms extending through January 2017. These contracts were entered into in the ordinary course of business to ensure rig availability to allow us to execute our business objectives in our key strategic plays. Future commitments as of March 31, 2014 total approximately $149 million, of which $82 million is expected to be incurred in the remainder of 2014, $47 million in 2015, $19 million in 2016, and $1 million in 2017. We expect to continue to enter into additional drilling rig contracts to help mitigate the risk of experiencing equipment shortages and rising costs that could delay our drilling projects or cause us to incur expenditures not provided for in our capital budget.
Pipeline transportation commitments – We have entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have varying terms extending as far as 2024, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of March 31, 2014 under the operational pipeline transportation arrangements amount to approximately $96 million, of which $15 million is expected to be incurred in the remainder of 2014, $19 million in 2015, $16 million in 2016, $11 million in 2017, $6 million in 2018, and $29 million thereafter.
Further, we are a party to additional 5-year firm transportation commitments for future crude oil pipeline projects being considered for development that are not yet operational. Such projects require the granting of regulatory approvals or otherwise require additional construction efforts by counterparties before being completed. Future commitments under the non-
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operational arrangements total approximately $1.0 billion at March 31, 2014, representing 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 exact 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 our 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, operators have indicated that certain pipeline projects may become operational in the second half of 2014, which would obligate us for transportation charges totaling $36 million in 2014, $143 million annually in years 2015 through 2018, and $106 million in 2019 associated with those projects.
Our pipeline commitments are for production primarily in the North region where we allocate a significant portion of our capital expenditures. We are not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.
Cost sharing commitment – The Company has entered into an arrangement to share certain costs associated with a local utility company's construction and installation of electrical infrastructure that will provide service to parts of North Dakota where the Company operates. This arrangement extends through January 2016 and requires the Company to make scheduled periodic payments based on the projected total cost of the project and the progress of construction. Future commitments under the arrangement as of March 31, 2014 total approximately $20 million, of which $10 million is expected to be incurred in 2014, $8 million in 2015, and $2 million in 2016.
We believe our cash flows from operations, our remaining cash balance, and amounts available under our credit facility, including our ability to increase our borrowing capacity thereunder, will be sufficient to satisfy the above commitments.
Critical Accounting Policies
There have been no changes in our critical accounting policies from those disclosed in our Form 10-K for the year ended December 31, 2013.
Recent Accounting Pronouncements Not Yet Adopted
We are monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and International Accounting Standards Board. There are a number of pending accounting standards being targeted for completion in 2014 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, and accounting for financial instruments. Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact these standards will have, if any, on our financial position, results of operations or cash flows.
Non-GAAP Financial Measures
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
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We believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our credit facility in place at March 31, 2014 requires that we maintain a total funded debt to EBITDAX ratio of no greater than 4.0 to 1.0 on a rolling four-quarter basis. This ratio represents the sum of outstanding borrowings and letters of credit under our credit facility plus our note payable and senior note obligations, divided by total EBITDAX for the most recent four quarters. We were in compliance with this covenant at March 31, 2014.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
Three months ended March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Net income | $ | 226,234 | $ | 140,627 | ||||
Interest expense | 62,975 | 47,475 | ||||||
Provision for income taxes | 132,867 | 82,590 | ||||||
Depreciation, depletion, amortization and accretion | 272,861 | 213,678 | ||||||
Property impairments | 58,208 | 40,081 | ||||||
Exploration expenses | 4,813 | 9,814 | ||||||
Impact from derivative instruments: | ||||||||
Total loss on derivatives, net | 39,674 | 84,831 | ||||||
Total cash paid on derivatives, net | (33,264 | ) | (6,810 | ) | ||||
Non-cash loss on derivatives, net | 6,410 | 78,021 | ||||||
Non-cash equity compensation | 11,039 | 9,242 | ||||||
EBITDAX | $ | 775,407 | $ | 621,528 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended March 31, | ||||||||
In thousands | 2014 | 2013 | ||||||
Net cash provided by operating activities | $ | 690,662 | $ | 458,111 | ||||
Current income tax provision | 1,552 | — | ||||||
Interest expense | 62,975 | 47,475 | ||||||
Exploration expenses, excluding dry hole costs | 4,813 | 7,553 | ||||||
Gain (loss) on sale of assets, net | (8,498 | ) | 136 | |||||
Other, net | (10,008 | ) | (3,176 | ) | ||||
Changes in assets and liabilities | 33,911 | 111,429 | ||||||
EBITDAX | $ | 775,407 | $ | 621,528 | ||||
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ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk |
General. We are exposed to a variety of market risks including commodity price risk, credit risk and interest rate risk. We address these risks through a program of risk management which may include the use of derivative instruments.
Commodity Price Risk. Our primary market risk exposure is in the pricing applicable to our crude oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil and natural gas has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the three months ended March 31, 2014, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $388 million for each $10.00 per barrel change in crude oil prices and $101 million for each $1.00 per Mcf change in natural gas prices.
To reduce price risk caused by these market fluctuations, we economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps ensure we have adequate funds available for our capital program. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also limits future revenues from upward price movements.
Changes in commodity prices during the three months ended March 31, 2014 had an overall negative impact on the fair value of our derivative instruments. For the three months ended March 31, 2014, we recognized cash losses on derivatives of $33.3 million and reported a non-cash mark-to-market loss on derivatives of $6.4 million. The fair value of our derivative instruments at March 31, 2014 was a net liability of $101.2 million. The mark-to-market net liability relates to derivative instruments with various terms that are scheduled to mature over the period from April 2014 through December 2016. Over this period, actual derivative settlements may differ significantly, either positively or negatively, from the mark-to-market valuation at March 31, 2014. An assumed increase in the forward commodity prices used in the March 31, 2014 valuation of our derivative instruments of $10.00 per barrel for crude oil and $1.00 per MMBtu for natural gas would increase our net derivative liability to approximately $649 million at March 31, 2014. Conversely, an assumed decrease in forward commodity prices of $10.00 per barrel for crude oil and $1.00 per MMBtu for natural gas would change our derivative valuation to a net asset of approximately $442 million at March 31, 2014.
Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and affiliates ($727 million in receivables at March 31, 2014), our joint interest receivables ($331 million at March 31, 2014), and counterparty credit risk associated with our derivative instrument receivables ($3 million at March 31, 2014).
We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to support crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.
Joint interest receivables arise from billing entities which own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $49.7 million at March 31, 2014, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.
Our use of derivative instruments involves the risk that our counterparties will be unable to meet their commitments under the arrangements. We manage this risk by using multiple counterparties who we consider to be financially strong in order to minimize our exposure to credit risk with any individual counterparty. All of our derivative contracts are with parties that are lenders (or affiliates of lenders) under our credit facility.
Interest Rate Risk. Our exposure to changes in interest rates relates primarily to any variable-rate borrowings we may have outstanding from time to time under our credit facility. We manage our interest rate exposure by monitoring both the effects of market changes in interest rates and the proportion of our debt portfolio that is variable-rate versus fixed-rate debt.
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We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We currently have no interest rate derivatives. We had $750 million of outstanding borrowings on our credit facility at May 1, 2014 with a weighted average interest rate of 1.7%. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $7.5 million per year and a $4.7 million decrease in net income per year.
ITEM 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2014 to ensure that information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the three months ended March 31, 2014, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Inherent Limitations on Controls and Procedures
A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even an effective system of internal control will provide only reasonable assurance that the objectives of the internal control system are met.
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PART II. Other Information
ITEM 1. | Legal Proceedings |
During the three months ended March 31, 2014 there have been no material changes with respect to the legal proceedings previously disclosed in our 2013 Form 10-K that was filed with the SEC on February 27, 2014. See Note 7. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements included elsewhere in this report.
ITEM 1A. | Risk Factors |
There have been no material changes in our risk factors from those disclosed in our 2013 Form 10-K.
In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our 2013 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q and in our 2013 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
(a) | Recent Sales of Unregistered Securities – Not applicable. |
(b) | Use of Proceeds – Not applicable. |
(c)Purchases of Equity Securities by the Issuer and Affiliated Purchasers – The following table provides information about purchases of equity securities registered by the Company pursuant to Section 12 of the Exchange Act during the three months ended March 31, 2014:
Period | Total number of shares purchased (1) | Average price paid per share (2) | Total number of shares purchased as part of publicly announced plans or programs | Maximum number of shares that may yet be purchased under the plans or programs (3) | |||||||||
January 1, 2014 to January 31, 2014 | — | $ | — | — | — | ||||||||
February 1, 2014 to February 28, 2014 | 23,221 | $ | 113.27 | — | — | ||||||||
March 1, 2014 to March 31, 2014 | — | $ | — | — | — | ||||||||
Total | 23,221 | $ | 113.27 | — | — | ||||||||
(1) | In connection with restricted stock grants under the Company's 2005 Long-Term Incentive Plan ("2005 Plan") and 2013 Long-Term Incentive Plan ("2013 Plan"), we adopted a policy that enables employees to surrender shares to cover their tax liability. In May 2013, the 2013 Plan was adopted and replaced the Company's 2005 Plan. Restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. All shares purchased above represent shares surrendered to cover tax liabilities. We paid the associated taxes to the Internal Revenue Service. |
(2) | The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares. |
(3) | We are unable to determine at this time the total amount of securities or approximate dollar value of securities that could potentially be surrendered to us pursuant to our policy that enables employees to surrender shares to cover their tax liability associated with the vesting of restrictions on shares. |
ITEM 3. | Defaults Upon Senior Securities |
Not applicable.
ITEM 4. | Mine Safety Disclosures |
Not applicable.
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ITEM 5. Other Information
Not applicable.
ITEM 6. | Exhibits |
The exhibits required to be filed pursuant to Item 601 of Regulation S-K are set forth in the Index to Exhibits accompanying this report and are incorporated herein by reference.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CONTINENTAL RESOURCES, INC. | ||||
Date: | May 7, 2014 | By: | /s/ John D. Hart | |
John D. Hart | ||||
Sr. Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer) | ||||
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Index to Exhibits
3.1 | Third Amended and Restated Certificate of Incorporation of Continental Resources, Inc. filed February 24, 2012 as Exhibit 3.1 to the Company’s 2011 Form 10-K (Commission File No. 001-32886) and incorporated herein by reference. |
3.2 | Third Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 6, 2012 and incorporated herein by reference. |
10.1*† | First Amendment to the Continental Resources, Inc. Deferred Compensation Plan. |
31.1* | Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241). |
31.2* | Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241). |
32** | Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350). |
101.INS** | XBRL Instance Document |
101.SCH** | XBRL Taxonomy Extension Schema Document |
101.CAL** | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF** | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB** | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE** | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith |
** | Furnished herewith |
† | Management contract or compensatory plan or arrangement filed pursuant to Item 601(b)(10)(iii) of Regulation S-K. |