SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20112013 |
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| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-32886
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
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| Oklahoma | | 73-0767549 |
(State or other jurisdiction of incorporation or organization)
| | Identification No.)
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30220 N. Independence, Suite 1500, Enid,Broadway, Oklahoma City, Oklahoma | | 7370173102 |
| (Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code:
(580) 233-8955(405) 234-9000
Securities registered underpursuant to Section 12(b) of the Act:
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Title of Class class | | Name of Each Exchangeeach exchange on Which Registered which registered |
| Common Stock, $0.01 par value | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the SecuritiesAct. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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| Large accelerated filer | | x | | Accelerated filer | | ¨ |
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| Non-accelerated filer | | ¨ (Do not check if a smaller reporting company) | | Smaller reporting company | | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30,
20112013 was approximately
$3.7$4.9 billion, based upon the closing price of
$64.91$86.06 per share as reported by the New York Stock Exchange on such date.
180,863,580
185,622,427 shares of our $0.01 par value common stock were outstanding on February
15, 2012.17, 2014.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of
StockholdersShareholders to be held in
2012,May 2014, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Form 10-K.
Table of Contents
Table of Contents
When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc.
and/orand our subsidiaries.
Glossary of Crude Oil and Natural Gas Terms
The terms defined in this section are used throughout this report:
“basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate. “Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids. “Bcf” One billion cubic feet of natural gas. “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. “de-risked” Refers to acreage and locations in which the Company believes the geological risks and uncertainties related to recovery of crude oil and natural gas have been reduced as a result of drilling operations to date. However, only a portion of such acreage and locations have been assigned proved undeveloped reserves and ultimate recovery of hydrocarbons from such acreage and locations remains subject to all risks of recovery applicable to other acreage. “developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production. “development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. “dry gas” Refers to natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also may refer to gas that has been processed or treated to remove all natural gas liquids. “dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities. “ECO-PadTM™” A Continental Resources, Inc. trademark which describes a well site layout which allows for drilling multiple wells from a single pad resulting in less environmental impact and lower drilling and completion costs. “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.i
“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.
“held by production” or“HBP” Refers to a mineralan oil and gas lease in which an entity is allowed to operate a property ascontinued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the property produces a minimum paying quantity of crude oilleased premises or natural gas.lands pooled therewith. “horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right anglehorizontally within a specified interval. “HPAI” High pressure air injection.
“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. “in-field well” A well drilled between producing wells in a field to provide more efficient recovery of crude oil or natural gas from the reservoir. “injection well” A well into which liquids or gases are injected in order to “push” additional crude oil or natural gas out of underground reservoirs and into the wellbores of producing wells. Typically considered an enhanced recovery process. “MBbl” One thousand barrels of crude oil, condensate or natural gas liquids. “Mcf” One thousand cubic feet of natural gas. “Mcfe” One thousand cubic feet of natural gas equivalent, with one barrel of crude oil being equivalent to six Mcf of natural gas based on the average equivalent energy content of the two commodities. “MMBo” One million barrels of crude oil. “MMBtu” One million British thermal units. “MMcf” One million cubic feet of natural gas. “MMcfe” One million cubic feet of natural gas equivalent, with one barrel of crude oil being equivalent to six Mcf of natural gas based on the average equivalent energy content of the two commodities. “microseismic” or “microseismic monitoring”Refers to the recording and imaging of seismic moments induced by hydraulic fracturing to provide technical data about fracture stimulation efficiency. This monitoring of fracture stimulations, being the industry's only measurement tool, yields technical data to allow for optimization of completion designs to help maximize production and/or reduce costs.
“net acres” or "net wells" Refers to the sum of the fractional working interests owned in gross acres or gross wells.
“NYMEX” The New York Mercantile Exchange. “net acres” The percentage of total acres an owner has out ofpad drilling" or "pad development" Describes a particular number of acres,well site layout which allows for drilling multiple wells from a single pad resulting in less environmental impact and lower drilling and completion costs. Also may be referred to as ECO-Pad drilling or a specified tract. An owner who has a 50% interest in 100 acres owns 50 net acres.development. “play” A term applied to 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.ii
“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. “PV-10” When used with respect to crude oil and natural gas reserves, PV-10 represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities and Exchange Commission (“SEC”). PV-10 is not a financial measure calculated in accordance with generally
accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company’s crude oil and natural gas properties. The Company and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
“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.
“spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies. “standardized measure” Discounted future net cash flows estimated by applying the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December (for 2009 and later) or year-end prices (for 2008 and prior) to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis in the crude oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.iii
“step-out well” or“step outs” A well drilled beyond the proved boundaries of a field to investigate a possible extension of the field. “3D (three dimensional seismic) defined locations” Locations that have been subjected to 3D seismic testing. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We do not typically evaluate reservoir productivity using 3D seismic technology. “3D seismic” Seismic surveys using an instrument to send sound waves into the earth and collect data to help geophysicists define the underground configurations. 3D seismic provides three-dimensional pictures. “unconventional play” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but require recently developed technologies to achieve profitability.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.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 andand/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. “waterflood” The injection of water into a crude oil reservoir to “push” additional crude oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process. “wellbore” The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called a well or borehole. “working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Cautionary Statement
Regarding Forward-Looking StatementsCertain statements and information in this report may constitute “forward-looking statements” withinfor the meaningPurpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995.1995
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”“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 underPart I, Item 1A. Risk Factors included in this report.report, quarterly reports, registration statements filed from time to time with the SEC, and other announcements we make from time to time. Without limiting the generality of the foregoing, certain statements incorporated by reference, if any, or included in this report constitute forward-looking statements.
Forward-looking statements may include statements about:
iv
crude oil and natural gas prices;
reserves;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;gas and flaring activities;
the amount, nature and timing of capital expenditures;
estimated revenues, expenses and results of operations;
drilling and completing of wells;
marketing of crude oil and natural gas;
transportation of crude oil, natural gas liquids, and natural gas to markets;
exploitation or property acquisitions;
acquisitions and dispositions;costs of exploiting and developing our properties and conducting other operations;
general economic conditions;
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; and
plans, objectives, expectations and intentions contained in this report that are not historical, including, without limitation, statements regarding our future growth plans.
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 that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling, completion and production equipment and services 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 underPart I, Item 1A. Risk Factors in this report, quarterly reports, and 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.
You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our
historical consolidated financial statements and the notes to those
historical consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “we,”
“ us,“us,” “our,” “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiaries.
We are an independent crude oil and natural gas exploration and production company with
operationsproperties 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
riverRiver and includes North Dakota Bakken, Montana Bakken,
and the Red River
units and the Niobrara play in Colorado and Wyoming.units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi
riverRiver including
various plays in the
Anadarko WoodfordSouth Central Oklahoma Oil Province (“SCOOP”), Northwest Cana and Arkoma
Woodford plays inareas of Oklahoma. The East region
contains propertiesis comprised of undeveloped leasehold acreage east of the Mississippi
river including the Illinois Basin and the state of Michigan.River.
We were originally formed in 1967 to explore for, develop and produce crude oil and natural gas properties. Through 1989, our activities and growth remained focused primarily in Oklahoma. In 1989, we expanded our activity into the North region. Our operations are now geographically concentrated in the North region, with that region comprising approximately 77% of our crude oil and natural gas production and approximately 86% of our crude oil and natural gas revenues for the year ended December 31, 2013. Approximately 71%76% of our estimated proved reserves as of December 31, 20112013 are located in the North region.
We completed an initial public offeringhave focused our operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2013, crude oil accounted for approximately 71% of our common stock in 2007,total production and approximately 87% of our common stock trades on the New York Stock Exchange under the ticker symbol “CLR”.crude oil and natural gas revenues. Crude oil represents approximately 68% of our estimated proved reserves as of December 31, 2013.
We focus our exploration activities in large new or developing
crude oil and liquids-rich natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where
three dimensional seismic, horizontal drilling,
geosteering technologies, advanced
completion technologies (e.g., fracture
stimulationstimulation) and enhanced recovery technologies allow us to economically develop and produce crude oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drill bit, adding
439.01,046 MMBoe of proved crude oil and natural gas reserves through extensions and discoveries from January 1,
20072009 through December 31,
20112013 compared to
4.885 MMBoe added through proved reserve acquisitions during that same period.
In October 2012, we announced a five-year growth plan to triple our production and proved reserves from year-end 2012 to year-end 2017.
As of December 31,
2011,2013, our estimated proved reserves were
508.41,084.1 MMBoe, with estimated proved developed reserves of
205.2406.8 MMBoe, or
40%38% of our total estimated proved reserves.
Crude oil comprised 64% of our total estimated proved reserves as of December 31, 2011. For the year ended December 31,
2011,2013, we generated crude oil and natural gas revenues of
$1.65$3.6 billion and operating cash flows of
$1.1$2.6 billion. For the year ended December 31,
2011,2013, daily production averaged
61,865135,919 Boe per day, a
43%39% increase over average production of
43,31897,583 Boe per day for the year ended December 31,
2010.2012. Average daily production for the quarter ended December 31,
20112013 increased
57%35% to
75,219144,254 Boe per day from
48,034106,831 Boe per day for the quarter ended December 31,
2010.2012.
The following table below summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2011,2013, average daily production for the quarter ended December 31, 20112013 and the reserve-to-production index in our principal regions. The PV-10 values shown below are not intended to represent the fair market value of our crude oil and natural gas properties. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. See “Critical Accounting Policies and Estimates” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report for further discussion of uncertainties inherent to the reserve estimates.
Our reserve estimates as of December 31,
20112013 are based primarily on a reserve report prepared by our independent reserve engineers, Ryder Scott Company,
L.P.L.P (“Ryder Scott”). In preparing its report, Ryder Scott evaluated properties representing approximately
96%99% of our PV-10,
97%99% of our proved crude oil reserves, and
81%94% of our proved natural gas reserves as of December 31,
2011.2013. Our internal technical staff evaluated the remaining properties. Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31,
20112013 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January
20112013 through December 2011,2013, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $96.19
$96.78 per Bbl for crude oil and
$4.12$3.67 per MMBtu for natural gas ($
88.7191.50 per Bbl for crude oil and
$5.59$5.36 per Mcf for natural gas adjusted for location and quality differentials).
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| | | At December 31, 2011 | | | Average daily
production for
fourth quarter
2011
(Boe per day) | | | | | | Annualized
reserve/production
index (2) | |
| | | Proved
reserves
(MBoe) | | | Percent
of total | | | PV-10 (1)
(In millions) | | | Net
producing
wells | | | | Percent
of total | | |
North Region: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Bakken field | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
North Dakota Bakken | | | 255,977 | | | | 50.4 | % | | $ | 4,996.3 | | | | 292 | | | | 35,565 | | | | 47.3 | % | | | 19.7 | |
Montana Bakken | | | 38,217 | | | | 7.5 | % | | | 848.8 | | | | 138 | | | | 5,678 | | | | 7.5 | % | | | 18.4 | |
Red River units | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cedar Hills | | | 48,147 | | | | 9.5 | % | | | 1,654.5 | | | | 132 | | | | 11,784 | | | | 15.7 | % | | | 11.2 | |
Other Red River units | | | 15,909 | | | | 3.1 | % | | | 362.0 | | | | 112 | | | | 3,462 | | | | 4.6 | % | | | 12.6 | |
Other | | | 4,213 | | | | 0.8 | % | | | 71.6 | | | | 211 | | | | 964 | | | | 1.3 | % | | | 12.0 | |
South Region: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oklahoma Woodford | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Anadarko Woodford | | | 93,637 | | | | 18.4 | % | | | 833.6 | | | | 56 | | | | 9,820 | | | | 13.0 | % | | | 26.1 | |
Arkoma Woodford | | | 38,977 | | | | 7.7 | % | | | 172.9 | | | | 57 | | | | 3,688 | | | | 4.9 | % | | | 29.0 | |
Other | | | 9,223 | | | | 1.8 | % | | | 134.8 | | | | 297 | | | | 3,080 | | | | 4.1 | % | | | 8.2 | |
East Region | | | 4,138 | | | | 0.8 | % | | | 125.8 | | | | 530 | | | | 1,178 | | | | 1.6 | % | | | 9.6 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 508,438 | | | | 100.0 | % | | $ | 9,200.3 | | | | 1,825 | | | | 75,219 | | | | 100.0 | % | | | 18.5 | |
|
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| | | December 31, 2013 | | Average daily
production for
fourth quarter
2013
(Boe per day) | | | | Annualized
reserve/production
index (2) |
| | | Proved
reserves
(MBoe) | | Percent
of total | | PV-10 (1)
(In millions) | | Net
producing
wells | | Percent
of total | |
| North Region: | | | | | | | | | | | | | | |
| Bakken field | | | | | | | | | | | | | | |
| North Dakota Bakken | | 688,741 |
| | 63.5 | % | | $ | 13,093 |
| | 779 |
| | 80,374 |
| | 55.7 | % | | 23.5 |
|
| Montana Bakken | | 52,401 |
| | 4.8 | % | | 1,437 |
| | 233 |
| | 12,961 |
| | 9.0 | % | | 11.1 |
|
| Red River units | | | | | | | |
|
| | | | | | |
| Cedar Hills | | 54,191 |
| | 5.0 | % | | 1,522 |
| | 130 |
| | 10,498 |
| | 7.3 | % | | 14.1 |
|
| Other Red River units | | 22,419 |
| | 2.1 | % | | 427 |
| | 131 |
| | 3,900 |
| | 2.7 | % | | 15.7 |
|
| Other | | 1,884 |
| | 0.2 | % | | 32 |
| | 16 |
| | 812 |
| | 0.6 | % | | 6.4 |
|
| South Region: | | | | | | | |
| | | | | | |
| SCOOP | | 214,667 |
| | 19.8 | % | | 3,286 |
| | 74 |
| | 23,754 |
| | 16.5 | % | | 24.8 |
|
| Northwest Cana | | 29,827 |
| | 2.8 | % | | 198 |
| | 73 |
| | 6,696 |
| | 4.6 | % | | 12.2 |
|
| Arkoma Woodford | | 11,103 |
| | 1.0 | % | | 69 |
| | 59 |
| | 2,769 |
| | 1.9 | % | | 11.0 |
|
| Other | | 8,892 |
| | 0.8 | % | | 111 |
| | 277 |
| | 2,490 |
| | 1.7 | % | | 9.8 |
|
| Total | | 1,084,125 |
| | 100.0 | % | | $ | 20,175 |
| | 1,772 |
| | 144,254 |
| | 100.0 | % | | 20.6 |
|
| |
| (1) | PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. The Standardized Measure at December 31, 2011 is $7.5 billion, a $1.7 billion difference from PV-10 becauserevenues of the tax effect.approximately $3.9 billion. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. |
| |
| (2) | The Annualized Reserve/Production Index is the number of years that estimated proved reserves would last assuming current production continued at the same rate. This index is calculated by dividing annualized fourth quarter 20112013 production into estimated proved reserve volumes at December 31, 2011.2013. |
The following table provides additional information regarding our key development areas as of December 31, 20112013 and the budgeted amounts we plan to spend on exploratory and development drilling, capital workovers, and facilities in 2012. | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | 2012 Plan | |
| | | Developed acres | | | Undeveloped acres | | | Gross wells
planned for
drilling | | | Capital
expenditures (1)
(in millions) | |
| | | Gross | | | Net | | | Gross | | | Net | | | |
North Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Bakken field | | | | | | | | | | | | | | | | | | | | | | | | |
North Dakota Bakken | | | 498,317 | | | | 236,052 | | | | 814,740 | | | | 427,185 | | | | 470 | | | $ | 989 | |
Montana Bakken | | | 97,367 | | | | 75,802 | | | | 250,423 | | | | 176,824 | | | | 18 | | | | 94 | |
Red River units | | | 150,534 | | | | 131,428 | | | | — | | | | — | | | | 12 | | | | 44 | |
Niobrara | | | | | | | | | | | | | | | | | | | | | | | | |
Colorado/Wyoming | | | 1,283 | | | | 1,013 | | | | 198,780 | | | | 114,495 | | | | 26 | | | | 59 | |
Other | | | 61,348 | | | | 45,624 | | | | 231,124 | | | | 129,383 | | | | 5 | | | | 9 | |
South Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Oklahoma Woodford | | | | | | | | | | | | | | | | | | | | | | | | |
Anadarko Woodford | | | 98,150 | | | | 56,634 | | | | 346,195 | | | | 221,482 | | | | 159 | | | | 377 | |
Arkoma Woodford | | | 105,967 | | | | 24,892 | | | | 26,931 | | | | 14,702 | | | | 1 | | | | 2 | |
Southern Woodford | | | 670 | | | | 130 | | | | 39,400 | | | | 14,322 | | | | — | | | | — | |
Other | | | 100,515 | | | | 47,435 | | | | 44,471 | | | | 18,974 | | | | 25 | | | | 44 | |
East Region | | | 48,832 | | | | 46,307 | | | | 137,202 | | | | 112,058 | | | | 43 | | | | 11 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 1,162,983 | | | | 665,317 | | | | 2,089,266 | | | | 1,229,425 | | | | 759 | | | $ | 1,629 | |
2014.
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 2014 Plan |
| | | Developed acres | | Undeveloped acres | | Gross wells
planned for
drilling | | Capital
expenditures (1)
(in millions) |
| | | Gross | | Net | | Gross | | Net | |
| North Region: | | | | | | | | | | | | |
| Bakken field | | | | | | | | | | | | |
| North Dakota Bakken | | 900,678 |
| | 530,682 |
| | 504,898 |
| | 378,370 |
| | 802 |
| | $ | 2,233 |
|
| Montana Bakken | | 159,943 |
| | 135,426 |
| | 214,358 |
| | 165,343 |
| | 68 |
| | 413 |
|
| Red River units | | 156,703 |
| | 137,294 |
| | — |
| | — |
| | 16 |
| | 50 |
|
| Niobrara - Colorado/Wyoming | | 12,087 |
| | 8,529 |
| | 126,662 |
| | 69,526 |
| | — |
| | — |
|
| Other | | 22,194 |
| | 7,220 |
| | 235,931 |
| | 179,265 |
| | 6 |
| | 40 |
|
| South Region: | | | | | | | | | | | | |
| SCOOP | | 74,019 |
| | 48,990 |
| | 603,665 |
| | 354,864 |
| | 159 |
| | 876 |
|
| Northwest Cana | | 120,668 |
| | 73,777 |
| | 110,120 |
| | 71,314 |
| | — |
| | 13 |
|
| Arkoma Woodford | | 110,973 |
| | 26,359 |
| | 4,568 |
| | 434 |
| | — |
| | — |
|
| Other | | 100,710 |
| | 46,008 |
| | 197,434 |
| | 167,506 |
| | 9 |
| | 65 |
|
| East Region | | — |
| | — |
| | 152,762 |
| | 144,363 |
| | — |
| | — |
|
| Total | | 1,657,975 |
| | 1,014,285 |
| | 2,150,398 |
| | 1,530,985 |
| | 1,060 |
| | $ | 3,690 |
|
| |
| (1) | CapitalThe capital expenditures budgeted for 20122014 as reflected above include amounts for drilling, capital workovers and facilities and exclude budgeted amounts for land of $94$300 million, seismic of $20$30 million, and $7$30 million for vehicles, computers and other equipment. Potential acquisition expenditures are not budgeted. We expect our cash flows from operations, our remaining cash balance, and the availability under our revolving credit facility will be sufficient to meet our capital expenditure needs for the next 12 months. The actual amount and timing of our capital expenditures may differ materially from our estimates as a result of, among other things, available cash flows, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. Further, a decline in crude oil and natural gas prices could cause us to curtail our actual capital expenditures. Conversely, an increase in commodity prices could result in increased capital expenditures. |
Our goal is to increase shareholder value by finding and developing crude oil and natural gas reserves at costs that provide an attractive rate of return on our investment. The principal elements of our business strategy are:
Focus on crude oil. During the late 1980s we began to believe the valuation potential for crude oil exceeded that of natural gas. Accordingly, we began to shift our reserve and production profiles toward crude oil. As of December 31, 2011,2013, crude oil comprises 64%comprised 68% of our total proved reserves and 73%71% of our 20112013 annual production. Although we do pursue liquids-rich natural gas opportunities, such as the Anadarko Woodford play in Oklahoma, we continue to believe crude oil valuations will be superior to natural gas valuations on a relative Btu basis for the foreseeable future. Growth Through Drilling. A substantial portion of our annual capital expenditures are invested in drilling projects and acreage acquisitions. From January 1, 20072009 through December 31, 2011,2013, proved crude oil and natural gas reserve additions through extensions and discoveries were 439.01,046 MMBoe compared to 4.885 MMBoe of proved reserve acquisitions. Internally Generated Prospects. Although we periodically evaluate and complete strategic acquisitions, our technical staff has internally generated a substantial portion of the opportunities for the investment of our capital. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than later entrants into a developing play. Focus on Unconventional Crude Oil and Natural Gas Resource Plays. Our experience with three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture stimulationstimulation) and enhanced recovery technologies allows us to commerciallyeconomically develop unconventional crude oil and natural gas resource reservoirs, such as the Red River B Dolomite, Bakken, Three Forks and Oklahoma Woodford formations. The Oklahoma Woodford is a widespread unconventional shale reservoir that produces in various basins across the state of Oklahoma, with our properties being primarily concentrated in the SCOOP, Northwest Cana and Arkoma areas of the play. Production rates in the Red River units also have been increasedsustained through the use of enhanced recovery technologies including water and high pressure air injection. Our production from the Red River units, the Bakken field, and the Oklahoma Woodford play comprised approximately 20,63548,324 MBoe, or 91%97%, of our total crude oil and natural gas production for the year ended December 31, 2011.2013. Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 969,010970,325 net undeveloped acres held in the Bakken play in North Dakota and Montana and the Oklahoma Woodford, play, and the Niobrara play in Colorado and Wyoming, we held 260,415560,660 net undeveloped acres in other crude oil and natural gas plays as of December 31, 2011.2013. Our technical staff is focused on identifying and testing new
unconventional crude oil and natural gas resource plays where significant reserves could be developed if economically producible volumes can be achieved through advanced drilling, fracture stimulation and enhanced recovery techniques.
We have a number of strengths we believe will help us successfully execute our business strategy:
Large Acreage Inventory. We own 1,229,425held 1,530,985 net undeveloped acres and 665,3171,014,285 net developed acres as of December 31, 2011.2013. Approximately 79%68% of the net undeveloped acres are located within unconventionalresource plays in the Bakken (North Dakota and Montana), Woodford (Oklahoma) and the Niobrara (Colorado and Wyoming). The remaining balance of the net undeveloped acreage is located in conventional plays including 3D-defined locations for the Trenton-Black River (Michigan), Lodgepole (North Dakota), Morrow-Springer (Western Oklahoma) and Frio (South Texas).
plays.
Experience with Horizontal Drilling and Enhanced Recovery ExperienceMethods. We have substantial experience with horizontal drilling and enhanced recovery methods. In 1992, we drilled our first horizontal well, and we have drilled over 1,1002,100 horizontal wells since that time. We continue to be a leader in the development of new drilling and completion technologies. Our trademarked ECO-Pad drilling concept, which allows for drilling multiple wells from a single pad, is becoming a standard drilling approach in the industry because it improves land use and increases operating efficiencies. We have drilled as many as 14 wells on a pad site and have the opportunity to increase this number in the future based on surface availability, technology and well spacing. We are also a leader in extending lateral drilling lengths, in some instances up to three miles. In 2012, we completed the first multiple-unit spaced well drilled in Oklahoma, which had a horizontal section that was twice the length of previous laterals in the area. Longer laterals are believed to have substantial experience with enhanced recovery methodsa positive impact on well productivity and currently serveeconomics. Additionally, we are a leader in the exploration and evaluation of the lower layers or “benches” of the Three Forks formation in the Bakken field (referred to as the operator"Lower Three Forks"), initially targeting the first bench of 49 waterflood units. Additionally,the Three Forks in mid-2008 followed by the successful completion of our first well in the second bench in October 2011. In 2012, we operate 6 high pressure air injection floods.successfully completed the first well ever drilled in the third bench of the Three Forks. In 2013, we completed our first of four pilot density projects in the Bakken and Three Forks formations, which included our first wells drilled in the fourth bench. The density project demonstrated the productive potential of multiple stacked zones and is helping us determine the optimum drilling and spacing pattern for future development of these reservoirs. Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2011,2013, we operated properties comprising 87% of our total proved reserves and 86% of our PV-10. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and fracture stimulation methods used. Experienced Management Team. Our senior management team has extensive expertise in the crude oil and natural gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the crude oil and natural gas industry in 1967. Our 79 senior officers have an average of 3130 years of crude oil and natural gas industry experience. Additionally,
Strong Financial Position. In the second half of 2013, our technical staff, which includes 48 petroleum engineers, 26 geoscientistscorporate credit rating was upgraded to investment grade by Moody’s Investor Services, Inc. and 26 landmen, has an average of 15 years experienceStandard & Poor’s Ratings Services. We have experienced significant growth with our success in the industry.development of the Bakken field and most recently the SCOOP play. Our growth has been matched with a disciplined capital sourcing approach which has enabled a strong credit profile. Strong Financial Position. We have a revolving credit facility with lender commitments totaling $1.25$1.5 billion and a borrowing base of $2.25 billion as of February 15, 2012, with available borrowing capacity of $347.2 million at that date after considering outstanding borrowings and letters of credit. While our current commitments total $1.25 billion, we have the ability to increase the aggregate commitment levelwhich may be increased up to the lesser of $2.5 billion or the borrowing base then in effect to provide additional available liquidity if needed to maintain our growth strategy, take advantage of business opportunities, and fund our capital program. We had $1.2 billion of available borrowing capacity under our credit facility at December 31, 2013 after considering outstanding borrowings and letters of credit. We believe our planned exploration and development activities will be funded substantially from our operating cash flows and borrowings under our revolving credit facility.facility borrowings. Our 20122014 capital expenditures budget has been established based on our current expectation of available cash flows from operations and availability under our revolving credit facility. Should expected available cash flows from operations materially differ from expectations, we believe our credit facility will havehas sufficient availability to fund any deficit or that we can reduce our capital expenditures to be in line with cash flows from operations.
Crude Oil and Natural Gas Operations
In December 2008, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for crude oil and natural gas companies. These rules became effective prospectively for annual reporting periods ending on or after December 31, 2009. The new rules, which we initially adopted for the year ended December 31, 2009, expanded the definition of crude oil and natural gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or natural gas, and activities undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The revised rules allow producers to report additional undrilled locations beyond one offset on each side of a producing well when there is reasonable certainty of economic producibility. Other definitions and terms were revised, including the definition of proved reserves, which was revised to require that entities must use the unweighted average of the first-day-of-the-month commodity prices over the preceding 12-month period, rather than the year-end price, when estimating whether reserve quantities are economical to produce. Likewise, the 12-month average price is now used to calculate reserves used in computing depreciation, depletion and amortization. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.
The initial application in 2009 of new rules related to modernizing the reserve calculation and disclosure requirements resulted in an upward adjustment to our total proved reserves as of December 31, 2009 primarily as a result of the amendments to the definition of crude oil and natural gas reserves and higher crude oil prices. SeeNotes to Consolidated Financial Statements—Note 17. Supplemental Crude Oil and Natural Gas Information (Unaudited).
Proved reserves are those 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.
TheIn connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence that the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott, our independent reserve engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps
including isopach and structure maps, analogy and statistical analysis, and available downhole and production data, seismic data and well test data.
The following tables set forth our estimated proved crude oil and natural gas reserves and PV-10 by reserve category as of December 31, 2011.2013. The total Standardized Measure of discounted cash flows as of December 31, 20112013 is also presented. Ryder Scott evaluated properties representing approximately 96%99% of our PV-10, 97%99% of our proved crude oil reserves, and 81%94% of our proved natural gas reserves as of December 31, 2011,2013, and our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K. Our estimated proved reserves and related future net revenues and PV-10 at December 31, 2011 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2011 through December 2011, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $96.19 per Bbl for crude oil and $4.12 per MMBtu for natural gas ($88.71 per Bbl for crude oil and $5.59 per Mcf for natural gas adjusted for location and quality differentials). | | | | | | | | | | | | | | | | |
| | | Crude Oil
(MBbls) | | | Natural Gas
(MMcf) | | | Total
(MBoe) | | | PV-10 (1)
(in millions) | |
Proved developed producing | | | 144,468 | | | | 361,265 | | | | 204,679 | | | $ | 5,617.1 | |
Proved developed non-producing | | | 556 | | | | — | | | | 556 | | | | 3.6 | |
Proved undeveloped | | | 181,109 | | | | 732,567 | | | | 303,203 | | | | 3,579.6 | |
| | | | | | | | | | | | | | | | |
Total proved reserves | | | 326,133 | | | | 1,093,832 | | | | 508,438 | | | $ | 9,200.3 | |
Standardized Measure | | | | | | | | | | | | | | $ | 7,505.4 | |
|
| | | | | | | | | | | | | |
| | | Crude Oil
(MBbls) | | Natural Gas
(MMcf) | | Total
(MBoe) | | PV-10 (1)
(in millions) |
| Proved developed producing | | 277,845 |
| | 761,729 |
| | 404,800 |
| | $ | 10,461.0 |
|
| Proved developed non-producing | | 785 |
| | 7,240 |
| | 1,992 |
| | 49.6 |
|
| Proved undeveloped | | 459,158 |
| | 1,309,051 |
| | 677,333 |
| | 9,664.8 |
|
| Total proved reserves | | 737,788 |
| | 2,078,020 |
| | 1,084,125 |
| | $ | 20,175.4 |
|
| Standardized Measure (1) | | | | | | | | $ | 16,295.8 |
|
| |
| (1) | PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. The Standardized Measure at December 31, 2011 is $7.5 billion, a $1.7 billion difference from PV-10 becauserevenues of the tax effect.approximately $3.9 billion. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. |
The following table provides additional information regarding our proved crude oil and natural gas reserves by region as of December 31, 2011. | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Proved Developed | | | Proved Undeveloped | |
| | | Crude
Oil
(MBbls) | | | Natural
Gas
(MMcf) | | | Total
(MBoe) | | | Crude
Oil
(MBbls) | | | Natural Gas
(MMcf) | | | Total
(MBoe) | |
North Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Bakken field | | | | | | | | | | | | | | | | | | | | | | | | |
North Dakota Bakken | | | 62,822 | | | | 93,023 | | | | 78,325 | | | | 146,418 | | | | 187,401 | | | | 177,652 | |
Montana Bakken | | | 16,480 | | | | 18,450 | | | | 19,555 | | | | 15,651 | | | | 18,064 | | | | 18,662 | |
Red River units | | | | | | | | | | | | | | | | | | | | | | | | |
Cedar Hills | | | 42,253 | | | | 17,611 | | | | 45,189 | | | | 2,958 | | | | — | | | | 2,958 | |
Other Red River units | | | 12,210 | | | | 347 | | | | 12,267 | | | | 3,642 | | | | — | | | | 3,642 | |
Other | | | 2,917 | | | | 6,758 | | | | 4,043 | | | | 20 | | | | 900 | | | | 170 | |
South Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Oklahoma Woodford | | | | | | | | | | | | | | | | | | | | | | | | |
Anadarko Woodford | | | 2,585 | | | | 103,830 | | | | 19,890 | | | | 11,950 | | | | 370,786 | | | | 73,747 | |
Arkoma Woodford | | | 110 | | | | 77,032 | | | | 12,949 | | | | 203 | | | | 154,950 | | | | 26,028 | |
Other | | | 1,901 | | | | 42,838 | | | | 9,042 | | | | 104 | | | | 466 | | | | 181 | |
East Region | | | 3,746 | | | | 1,376 | | | | 3,975 | | | | 163 | | | | — | | | | 163 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 145,024 | | | | 361,265 | | | | 205,235 | | | | 181,109 | | | | 732,567 | | | | 303,203 | |
2013.
|
| | | | | | | | | | | | | | | | | | |
| | | Proved Developed | | Proved Undeveloped |
| | | Crude Oil
(MBbls) | | Natural Gas
(MMcf) | | Total
(MBoe) | | Crude Oil
(MBbls) | | Natural Gas
(MMcf) | | Total
(MBoe) |
| North Region: | | | | | | | | | | | | |
| Bakken field | | | | | | | | | | | | |
| North Dakota Bakken | | 159,372 |
| | 260,318 |
| | 202,759 |
| | 401,841 |
| | 504,846 |
| | 485,982 |
|
| Montana Bakken | | 31,727 |
| | 32,169 |
| | 37,088 |
| | 12,771 |
| | 15,252 |
| | 15,313 |
|
| Red River units | | | | | | | | | | | | |
| Cedar Hills | | 51,263 |
| | 7,039 |
| | 52,436 |
| | 1,755 |
| | — |
| | 1,755 |
|
| Other Red River units | | 17,472 |
| | 13,400 |
| | 19,705 |
| | 2,714 |
| | — |
| | 2,714 |
|
| Other | | 619 |
| | 7,590 |
| | 1,884 |
| | — |
| | — |
| | — |
|
| South Region: | | | | | | | | | | | | |
| SCOOP | | 14,607 |
| | 238,629 |
| | 54,379 |
| | 39,096 |
| | 727,150 |
| | 160,288 |
|
| Northwest Cana | | 1,433 |
| | 102,676 |
| | 18,546 |
| | 981 |
| | 61,803 |
| | 11,281 |
|
| Arkoma Woodford | | 18 |
| | 66,509 |
| | 11,103 |
| | — |
| | — |
| | — |
|
| Other | | 2,119 |
| | 40,639 |
| | 8,892 |
| | — |
| | — |
| | — |
|
| Total | | 278,630 |
| | 768,969 |
| | 406,792 |
| | 459,158 |
| | 1,309,051 |
| | 677,333 |
|
We have historically added reserves through our exploration program and development activities as discussedin Part I, Item 1. Business—Crude Oil and Natural Gas Operations. Reserves at December 31, 2009, 2010 and 2011 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules. Reserves at December 31, 2008 were computed using year-end commodity prices pursuant to previous SEC rules. ChangesThe following table provides information regarding changes in total proved reserves were as follows for the periods indicated:presented. | | | | | | | | | | | | |
| | | Year Ended December 31, | |
MBoe | | 2011 | | | 2010 | | | 2009 | |
Proved reserves at beginning of year | | | 364,712 | | | | 257,293 | | | | 159,262 | |
Revisions of previous estimates | | | 2,237 | | | | 27,629 | | | | 1,195 | |
Extensions, discoveries and other additions | | | 161,981 | | | | 95,233 | | | | 110,454 | |
Production | | | (22,581 | ) | | | (15,811 | ) | | | (13,623 | ) |
Sales of minerals in place | | | — | | | | — | | | | — | |
Purchases of minerals in place | | | 2,089 | | | | 368 | | | | 5 | |
| | | | | | | | | | | | |
Proved reserves at end of year | | | 508,438 | | | | 364,712 | | | | 257,293 | |
|
| | | | | | | | | |
| | | Year Ended December 31, |
| MBoe | | 2013 | | 2012 | | 2011 |
| Proved reserves at beginning of year | | 784,677 |
| | 508,438 |
| | 364,712 |
|
| Revisions of previous estimates | | (96,054 | ) | | 4,149 |
| | 2,237 |
|
| Extensions, discoveries and other additions | | 444,654 |
| | 233,652 |
| | 161,981 |
|
| Production | | (49,610 | ) | | (35,716 | ) | | (22,581 | ) |
| Sales of minerals in place | | — |
| | (7,838 | ) | | — |
|
| Purchases of minerals in place | | 458 |
| | 81,992 |
| | 2,089 |
|
| Proved reserves at end of year | | 1,084,125 |
| | 784,677 |
| | 508,438 |
|
Revisions. Revisions of previous estimates. Revisions represent changes in previous reserve estimates, upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions for the year ended December 31, 2010 were due2013 primarily represent the removal of proved undeveloped ("PUD") reserves resulting from a decision in 2013 to better than anticipated production performanceallocate a greater focus of our 5-year growth plan to our drilling programs in higher rates-of-return crude oil and higher average commodity prices throughout 2010 as comparedliquids-rich natural gas areas of the Bakken and SCOOP while continuing to 2009.build on the early success in our development of the Lower Three Forks reservoirs in the Bakken. Another contributing factor is our increased focus on multi-well pad drilling in the Bakken, which resulted in the removal of PUDs in certain areas in favor of PUDs more likely to be developed with pad drilling where operating efficiencies may be realized to maximize rates of return. These factors contributed to the removal of 81 MMBoe of PUD reserves in 2013.Extensions, discoveries and other additions. These are additions to our proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for the year ended December 31, 2009 include increases in proved undeveloped locations as a resulteach of the changethree years reflected in the SEC’s rules in 2009 to allow producers to report additional undrilled locations beyond one offset on each side of a producing well where there isreasonable certainty of economic producibility. Extensions, discoveries and other additions for the year ended December 31, 2010table above were primarily due to increases in proved reserves associated with our successful drilling activity and strong production growth in the Bakken fieldfield. Proved reserve additions in North Dakota. Extensions, discoveries and other additionsthe Bakken totaled 276 MMBoe for the year ended December 31, 20112013. Additionally, 2013 extensions and discoveries were primarily due to increases in proved reserves associated with oursignificantly impacted by successful drilling activityresults in the emerging SCOOP play, resulting in 158 MMBoe of proved reserve additions during the year. Significant progress continued to be made in 2013 in developing and expanding our Bakken and SCOOP assets, both laterally and vertically, through strategic exploration, development, planning and technology. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2013 drilling
activities in the Bakken
field in North Dakota and
Anadarko Woodford play in Oklahoma.SCOOP plays, among others. We expect a significant portion of future reserve additions will come from our major development projects in the Bakken and Anadarko Woodford plays.SCOOP.
Sales of minerals in place. These are reductions to proved reserves that result from the disposition of properties during a period. During the year ended December 31, 2012, we disposed of certain non-strategic properties in Oklahoma, Wyoming, and our East region in an effort to redeploy capital to our strategic areas that we believe will deliver higher future growth potential. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions for further discussion of our 2012 dispositions. We also expectmay continue to seek opportunities to sell non-strategic properties if and when we have the ability to dispose of such assets at competitive terms.
Purchases of minerals in place. These are additions to proved reserves that result from the acquisition of properties during a period. Purchases for the year ended December 31, 2012 primarily reflect the Company’s acquisitions of properties in the Bakken play of North Dakota. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions and Note 14. Property Transaction with Related Party for further discussion of our 2012 acquisitions. We may continue to participate as a buyer of properties when and if we have the ability to increase our position in strategic plays at favorablecompetitive terms. Proved Undeveloped Reserves
Our PUD reserves at December 31, 2013 totaled 677,333 MBoe, consisting of 459,158 MBbls of crude oil and 1,309,051 MMcf of natural gas. PUD reserves at December 31, 2013 were concentrated in the Bakken and SCOOP plays, our most active development areas, with those districts comprising 74% and 24%, respectively, of our total PUD reserves at year-end 2013. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2013. |
| | | | | | | | | |
| | | Crude Oil
(MBbls) | | Natural Gas
(MMcf) | | Total
(MBoe) |
| Proved undeveloped reserves at December 31, 2012 | | 334,293 |
| | 795,585 |
| | 466,891 |
|
| Revisions of previous estimates | | (52,440 | ) | | (251,475 | ) | | (94,354 | ) |
| Extensions and discoveries | | 240,653 |
| | 981,118 |
| | 404,173 |
|
| Purchases of minerals in place | | 23 |
| | 26 |
| | 28 |
|
| Conversion to proved developed reserves | | (63,371 | ) | | (216,203 | ) | | (99,405 | ) |
| Proved undeveloped reserves at December 31, 2013 | | 459,158 |
| | 1,309,051 |
| | 677,333 |
|
Revisions of previous estimates. During the year ended December 31, 2013, we removed 315 gross (174 net) PUD locations, which resulted in the removal of 42 MMBo and 235 Bcf (81 MMBoe) of PUD reserves. These removals were due to the aforementioned decision to allocate a greater focus of our 5-year growth plan to drilling programs in higher rates-of-return areas of the Bakken, SCOOP, and Lower Three Forks, with increased focus on areas capable of being developed via multi-well pad drilling. These factors contributed to the removal of PUD reserves in certain areas having less attractive rates of return or are otherwise less likely to be developed via pad drilling.
Extensions and discoveries. Extensions and discoveries were primarily due to increases in PUD reserves associated with our successful drilling activity in the Bakken and SCOOP. PUD reserve additions in the Bakken totaled 205 MMBo and 258 Bcf (248 MMBoe) in 2013, while SCOOP PUD reserve additions totaled 33 MMBo and 687 Bcf (147 MMBoe). See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2013 drilling activities in the Bakken and SCOOP plays.
Conversion to proved developed reserves. In 2013, we developed approximately 21% of our PUD reserves and 20% of our PUD locations booked as of December 31, 2012 through the drilling of 360 gross (208 net) development wells at an aggregate capital cost of approximately $1.7 billion.
Development plans. We have acquired substantial leasehold positions in the Bakken field and SCOOP play. Our drilling programs to date in those areas have focused on proving our undeveloped leasehold acreage through strategic exploratory drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease. While we will continue to drill strategic exploratory wells and build on our current leasehold position, we expect to continue increasing our focus on developing our PUD locations. Development of our existing PUD reserves at December 31, 2013 is expected to occur within five years of the date of initial booking of the PUDs. Estimated future development costs relating to the development of PUD reserves are projected to be approximately $2.5 billion in 2014, $2.2 billion in 2015, $2.3 billion in 2016, $2.0 billion in 2017, and $1.0 billion in 2018. We expect our cash flows from operations and our credit facility
will be sufficient to fund these future development costs. We had no PUD reserves at December 31, 2013 that remained undeveloped beyond five years from the date of initial booking.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process.
Ryder Scott, our independent
reserve engineers,reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC,
96%99% of our PV-10,
97%99% of our proved crude oil reserves, and
81%94% of our proved natural gas reserves as of December 31,
20112013 included in this Annual Report on Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Annual Report on Form 10-K for further discussion of the qualifications of Ryder Scott personnel.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. In the fourth quarter, our technical team
meetsis in contact regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates.
While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, aA copy of the Ryder Scott reserve report is reviewed by our Audit Committee with representatives of Ryder Scott and by our internal technical staff before
dissemination of the
information.information is filed with the SEC on Form 10-K. Additionally, certain members of our senior management review and approve the Ryder Scott reserve report and on a quarterly basis
review any internally estimated significant changes to our proved reserves.
Our Vice President—
Resource DevelopmentCorporate Engineering is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, an MBA in Finance and
2629 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Vice President—
Resource DevelopmentCorporate Engineering reports directly to our
President and Chief Operating Officer.Senior Vice President—Operations. The reserve estimates are reviewed and approved by the
President and Chief Operating Officer and certain
other members of senior management.
Proved Undeveloped Reserves. Our proved undeveloped (“PUD”) reserves at December 31, 2011 were 303,203 MBoe, consisting of 181,109 MBbls of crude oil and 732,567 MMcf of natural gas. In 2011, we developed approximately 13% of our proved undeveloped reserves booked as of December 31, 2010 through the drilling of 141 gross (68.2 net) development wells at an aggregate capital cost of approximately $448 million. Also in 2011, we removed 230 gross (49.9 net) PUD locations. This resulted in the removal of 1.7 MMBo and 135.4 Bcf of proved undeveloped reserves (24.2 MMBoe). These removals were predominantly due to our decision to declassify 0.2 MMBo and 130.4 Bcf (21.9 MMBoe) of proved undeveloped reserves in our Arkoma Woodford district, which consists primarily of dry gas. These reserves were originally scheduled to be developed by year-end 2013. However, given current and projected prices for natural gas, we elected to defer drilling and as a result declassified these proved undeveloped reserves accordingly. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $1.5 billion in 2012, $1.6 billion in 2013, $1.4 billion in 2014, $0.5 billion in 2015 and $0.2 billion in 2016.
Since our entry into the Bakken field, we have acquired a substantial leasehold position. Our drilling programs to date have focused on proving our undeveloped leasehold acreage through strategic exploratory drilling, thereby
increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease with drilling obligations. While we will continue to drill strategic exploratory wells and build on our current leasehold position, we will simultaneously increase our focus on drilling programs over the next 5 years which harvest our PUD locations. Our current 5 year plan anticipates that full development of our PUD inventory will comprise the majority of our currently projected level of drilling activity and generate additional PUD locations as our current inventory is harvested.
Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acreageacres by region as of December 31, 2011: | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Developed Acres | | | Undeveloped Acres | | | Total | |
| | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
North Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Bakken field | | | | | | | | | | | | | | | | | | | | | | | | |
North Dakota Bakken | | | 498,317 | | | | 236,052 | | | | 814,740 | | | | 427,185 | | | | 1,313,057 | | | | 663,237 | |
Montana Bakken | | | 97,367 | | | | 75,802 | | | | 250,423 | | | | 176,824 | | | | 347,790 | | | | 252,626 | |
Red River units | | | 150,534 | | | | 131,428 | | | | — | | | | — | | | | 150,534 | | | | 131,428 | |
Niobrara | | | | | | | | | | | | | | | | | | | | | | | | |
Colorado/Wyoming | | | 1,283 | | | | 1,013 | | | | 198,780 | | | | 114,495 | | | | 200,063 | | | | 115,508 | |
Other | | | 61,348 | | | | 45,624 | | | | 231,124 | | | | 129,383 | | | | 292,472 | | | | 175,007 | |
South Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Oklahoma Woodford | | | | | | | | | | | | | | | | | | | | | | | | |
Anadarko Woodford | | | 98,150 | | | | 56,634 | | | | 346,195 | | | | 221,482 | | | | 444,345 | | | | 278,116 | |
Arkoma Woodford | | | 105,967 | | | | 24,892 | | | | 26,931 | | | | 14,702 | | | | 132,898 | | | | 39,594 | |
Southern Woodford | | | 670 | | | | 130 | | | | 39,400 | | | | 14,322 | | | | 40,070 | | | | 14,452 | |
Other | | | 100,515 | | | | 47,435 | | | | 44,471 | | | | 18,974 | | | | 144,986 | | | | 66,409 | |
East Region | | | 48,832 | | | | 46,307 | | | | 137,202 | | | | 112,058 | | | | 186,034 | | | | 158,365 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 1,162,983 | | | | 665,317 | | | | 2,089,266 | | | | 1,229,425 | | | | 3,252,249 | | | | 1,894,742 | |
2013:
|
| | | | | | | | | | | | | | | | | | |
| | | Developed acres | | Undeveloped acres | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| North Region: | | | | | | | | | | | | |
| Bakken field | | | | | | | | | | | | |
| North Dakota Bakken | | 900,678 |
| | 530,682 |
| | 504,898 |
| | 378,370 |
| | 1,405,576 |
| | 909,052 |
|
| Montana Bakken | | 159,943 |
| | 135,426 |
| | 214,358 |
| | 165,343 |
| | 374,301 |
| | 300,769 |
|
| Red River units | | 156,703 |
| | 137,294 |
| | — |
| | — |
| | 156,703 |
| | 137,294 |
|
| Niobrara - Colorado/Wyoming | | 12,087 |
| | 8,529 |
| | 126,662 |
| | 69,526 |
| | 138,749 |
| | 78,055 |
|
| Other | | 22,194 |
| | 7,220 |
| | 235,931 |
| | 179,265 |
| | 258,125 |
| | 186,485 |
|
| South Region: | | | | | | | | | | | | |
| SCOOP | | 74,019 |
| | 48,990 |
| | 603,665 |
| | 354,864 |
| | 677,684 |
| | 403,854 |
|
| Northwest Cana | | 120,668 |
| | 73,777 |
| | 110,120 |
| | 71,314 |
| | 230,788 |
| | 145,091 |
|
| Arkoma Woodford | | 110,973 |
| | 26,359 |
| | 4,568 |
| | 434 |
| | 115,541 |
| | 26,793 |
|
| Other | | 100,710 |
| | 46,008 |
| | 197,434 |
| | 167,506 |
| | 298,144 |
| | 213,514 |
|
| East Region | | — |
| | — |
| | 152,762 |
| | 144,363 |
| | 152,762 |
| | 144,363 |
|
| Total | | 1,657,975 |
| | 1,014,285 |
| | 2,150,398 |
| | 1,530,985 |
| | 3,808,373 |
| | 2,545,270 |
|
The following table sets forth the number of gross and net undeveloped acres as of December 31, 20112013 that willare expected to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates: | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2012 | | | 2013 | | | 2014 | |
| | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
North Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Bakken field | | | | | | | | | | | | | | | | | | | | | | | | |
North Dakota Bakken | | | 171,591 | | | | 82,009 | | | | 308,952 | | | | 145,590 | | | | 159,951 | | | | 86,453 | |
Montana Bakken | | | 18,870 | | | | 17,605 | | | | 93,131 | | | | 54,824 | | | | 86,546 | | | | 67,196 | |
Red River units | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
Niobrara | | | | | | | | | | | | | | | | | | | | | | | | |
Colorado/Wyoming | | | 1,200 | | | | 969 | | | | 52,165 | | | | 32,380 | | | | 14,778 | | | | 9,408 | |
Other | | | 42,921 | | | | 21,419 | | | | 52,117 | | | | 38,812 | | | | 5,580 | | | | 3,480 | |
South Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Oklahoma Woodford | | | | | | | | | | | | | | | | | | | | | | | | |
Anadarko Woodford | | | 50,995 | | | | 29,721 | | | | 156,018 | | | | 100,829 | | | | 102,086 | | | | 63,923 | |
Arkoma Woodford | | | 12,199 | | | | 6,696 | | | | 7,330 | | | | 5,118 | | | | 240 | | | | 173 | |
Southern Woodford | | | 5,915 | | | | 3,015 | | | | 11,840 | | | | 4,317 | | | | 19,666 | | | | 6,489 | |
Other | | | 3,729 | | | | 2,060 | | | | 6,070 | | | | 4,210 | | | | 7,160 | | | | 2,575 | |
East Region | | | 63,313 | | | | 56,351 | | | | 41,018 | | | | 32,424 | | | | 7,709 | | | | 5,699 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 370,733 | | | | 219,845 | | | | 728,641 | | | | 418,504 | | | | 403,716 | | | | 245,396 | |
dates or the leases are renewed.
|
| | | | | | | | | | | | | | | | | | |
| | | 2014 | | 2015 | | 2016 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| North Region: | | | | | | | | | | | | |
| Bakken field | | | | | | | | | | | | |
| North Dakota Bakken | | 126,232 |
| | 84,679 |
| | 143,555 |
| | 118,609 |
| | 107,462 |
| | 107,257 |
|
| Montana Bakken | | 63,762 |
| | 51,399 |
| | 65,541 |
| | 46,973 |
| | 38,375 |
| | 36,632 |
|
| Red River units | | 2,716 |
| | 1,377 |
| | 7,967 |
| | 5,423 |
| | 12,054 |
| | 12,042 |
|
| Niobrara - Colorado/Wyoming | | 13,574 |
| | 8,800 |
| | 83,531 |
| | 45,692 |
| | 23,538 |
| | 10,816 |
|
| Other | | 3,063 |
| | 1,873 |
| | 10,991 |
| | 4,101 |
| | 1,440 |
| | 588 |
|
| South Region: | | | | | | | | | | | | |
| SCOOP | | 122,067 |
| | 71,061 |
| | 105,279 |
| | 58,198 |
| | 151,040 |
| | 81,042 |
|
| Northwest Cana | | 34,804 |
| | 21,997 |
| | 27,686 |
| | 15,668 |
| | 33,024 |
| | 26,521 |
|
| Arkoma Woodford | | 1,040 |
| | 120 |
| | — |
| | — |
| | — |
| | — |
|
| Other | | 1,202 |
| | 733 |
| | 85,919 |
| | 64,276 |
| | 15,932 |
| | 16,767 |
|
| East Region | | 9,657 |
| | 7,486 |
| | 14,187 |
| | 9,760 |
| | 5,128 |
| | 4,695 |
|
| Total | | 378,117 |
| | 249,525 |
| | 544,656 |
| | 368,700 |
| | 387,993 |
| | 296,360 |
|
During the three years ended December 31,
2011,2013, we drilled exploratory and development wells as set forth in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
Exploratory wells: | | | | | | | | | | | | | | | | | | | | | | | | |
Crude oil | | | 50 | | | | 23.4 | | | | 42 | | | | 11.8 | | | | 14 | | | | 6.5 | |
Natural gas | | | 109 | | | | 45.9 | | | | 25 | | | | 10.9 | | | | 34 | | | | 9.0 | |
Dry holes | | | 2 | | | | 1.3 | | | | 4 | | | | 2.2 | | | | 16 | | | | 9.0 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total exploratory wells | | | 161 | | | | 70.6 | | | | 71 | | | | 24.9 | | | | 64 | | | | 24.5 | |
Development wells: | | | | | | | | | | | | | | | | | | | | | | | | |
Crude oil | | | 380 | | | | 126.1 | | | | 231 | | | | 91.5 | | | | 106 | | | | 39.1 | |
Natural gas | | | 17 | | | | 1.6 | | | | 44 | | | | 5.2 | | | | 45 | | | | 4.1 | |
Dry holes | | | 5 | | | | 0.6 | | | | 3 | | | | 1.0 | | | | 2 | | | | 0.1 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total development wells | | | 402 | | | | 128.3 | | | | 278 | | | | 97.7 | | | | 153 | | | | 43.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total wells | | | 563 | | | | 198.9 | | | | 349 | | | | 122.6 | | | | 217 | | | | 67.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | 2013 | | 2012 | | 2011 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Exploratory wells: | | | | | | | | | | | | |
| Crude oil | | 75 |
| | 51.5 |
| | 76 |
| | 37.0 |
| | 50 |
| | 23.4 |
|
| Natural gas | | 40 |
| | 23.7 |
| | 78 |
| | 43.8 |
| | 109 |
| | 45.9 |
|
| Dry holes | | 3 |
| | 2.1 |
| | 1 |
| | 1.0 |
| | 2 |
| | 1.3 |
|
| Total exploratory wells | | 118 |
| | 77.3 |
| | 155 |
| | 81.8 |
| | 161 |
| | 70.6 |
|
| Development wells: | | | | | �� | | | | | | | |
| Crude oil | | 734 |
| | 250.9 |
| | 561 |
| | 211.3 |
| | 380 |
| | 126.1 |
|
| Natural gas | | 26 |
| | 5.4 |
| | 5 |
| | 2.4 |
| | 17 |
| | 1.6 |
|
| Dry holes | | — |
| | — |
| | 3 |
| | 1.1 |
| | 5 |
| | 0.6 |
|
| Total development wells | | 760 |
| | 256.3 |
| | 569 |
| | 214.8 |
| | 402 |
| | 128.3 |
|
| Total wells | | 878 |
| | 333.6 |
| | 724 |
| | 296.6 |
| | 563 |
| | 198.9 |
|
As of December 31,
2011,2013, there were
195404 gross
(62.2(160.8 net) wells in the process of drilling, completing or waiting on completion.
As of February 15, 2012,17, 2014, we operated 3643 rigs on our properties. Our rig activity during 20122014 will depend on potential drilling efficiency gains and crude oil and natural gas prices and, accordingly, our rig count may increase or decrease from current levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost. SeePart I, Item 1A. Risk Factors—The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
Summary of Crude Oil and Natural Gas Properties and Projects
Throughout the following discussion, we discuss our budgeted number of wells and capital expenditures for
2012.2014. Although we cannot provide any assurance, we believe our cash flows from operations, remaining cash balance, and
borrowing availability under our
revolving credit facility,
including our ability to increase our borrowing capacity thereunder, will be sufficient to satisfy our
20122014 capital budget.
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. The actual amount and timing of our capital expenditures may differ materially from our estimates as a result of, among other things, available cash flows,
unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment,
the availability of transportation capacity, and regulatory, technological and competitive developments. Further, 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.
As referred to throughout this report, a “play” is a term applied to 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. “Conventional plays” are areas believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps. “Unconventional plays” are areas believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but
generally require
recently developed technologieshorizontal drilling, fracture stimulation treatments or other special recovery processes to achieve
profitability.economic production. Unconventional plays 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. Our operations in unconventional plays include operations in the Bakken and Woodford plays and the Red River units. Our operations within conventional plays include operations in the
Trenton-Black River of Michigan, Lodgepole of North Dakota, Morrow-Springer of western Oklahoma and Frio in south Texas. In general, unconventional plays require the application of more advanced technology and higher drilling and completion costs to produce relative to conventional plays. These technologies can include hydraulic fracturing treatments, horizontal wellbores, multilateral wellbores, or some other technique or combination of techniques to expose more of the reservoir to the wellbore.
References throughout this report to “3D seismic” refer to seismic surveys of areas by means of an instrument which records the travel time of vibrations sent through the earth and the interpretation thereof. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are better able to define the underground configurations. “3D defined locations” are those locations that have been subjected to 3D seismic testing. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We do not typically evaluate reservoir productivity using 3D seismic technology.
Our properties in the North region represented 86%82% of our PV-10 as of December 31, 2011. During2013 and 75% of our average daily Boe production for the three months ended December 31, 2011,2013. For the three months ended December 31, 2013, our average daily production from such properties was 50,529 net Bbls108,545 Boe per day, an increase of crude oil and 41,545 net Mcf of natural gas.30% over our average daily production for the three months ended December 31, 2012. Our principal producing properties in thisthe North region are in the Bakken field and the Red River units.
The Bakken field of North Dakota and Montana is one of the premier crude oil resource plays in the United States.
It has been described byIn April 2013, the
United StatesU.S. Geological Survey
(“USGS”) asreleased an updated estimate of reserves located in the
largest continuous crude oil accumulation it has ever assessed. Estimates of recoverable reserves forBakken field. The assessment projects that the Bakken field
have grown from 4.3contains an estimated mean of 7.4 billion barrels, with a potential of up to 11.4 billion barrels, of
undiscovered, technically recoverable crude oil
as published inusing current technology. Total production from the Bakken field reached a
report issued by the USGS in April 2008, to potentially 11 billionrecord 1.1 million barrels of
crude oil
equivalent ("MMBoe") per day in
North Dakota alone, as reportedOctober 2013, up 39% over October 2012 based on data published by
IHS Inc. and the North Dakota Industrial
Commission (“NDIC”) in January 2011. The increase in reserves is a result of improved drilling and completion technologies andCommission. North Dakota remains the
additional reserves foundsecond largest oil producing state in the
Three Forks formation. In October 2011, the USGS began a study to update their 2008 assessment of recoverable reserves for the Bakken field to reflect the increased recoveriesU.S. due to
new geologic models applied to the Bakken Formation, advances in drilling and production
technologies, and additional crude oil discoveries in the field. Results of the USGS study are expected to be announced in 2013.Drilling activity and production ratesgrowth in the Bakken field continued to increase in 2011, reaching record levels in North Dakota, according to a report issued by the NDIC on January 17, 2012.field. As of February 6, 2012,December 31, 2013, there were 210183 rigs actively drilling in the Bakken field, up 21% from the 174 rigs that were drilling as of February 18, 2011. field.
We continue to be a leader in the developmentleading producer, leasehold owner and expansion of the Bakken field. We control one of the largest leasehold positions with approximately 1,660,847 gross (915,863 net) acres as of December 31, 2011. We are also the most active driller in the Bakken field. Our Bakken field with 22 operated rigs drilling as of February 15, 2012. During 2011 we completed 390 gross (122.3 net) wells inproduction averaged 93,335 Boe per day during the three months ended December 31, 2013, up 38% from our average daily Bakken field.field production for the three months ended December 31, 2012. Our properties within the Bakken field represented 64%72% of our PV-10 as of December 31, 20112013 and 55%65% of our average daily Boe production for the three months ended December 31, 2011.2013. Our total proved Bakken field reserves as of December 31, 2013 were 741 MMBoe, up 32% over our proved Bakken field reserves as of December 31, 2012. As of December 31, 20112013, we controlled the largest leasehold position in the Bakken field with 1,779,877 gross (1,209,821 net) acres. Approximately 55% of our net acreage was developed and the remaining 45% was undeveloped as of December 31, 2013. As of December 31, 2013, we were the most active driller in the Bakken field, with 20 active operated rigs. As of December 31, 2013, we had completed 1,0422,636 gross (382.9(1,025 net) wells in the Bakken field. Our
inventory of proved undeveloped drilling locations in the Bakken field as of December 31, 20112013 totaled 1,1311,964 gross (497.4(1,119 net) wells.During 2011, we saw
We made significant progress with our production, reservesdevelopment and acreage positionexploration drilling programs in the Bakken field grow while substantial portionsduring 2013, completing a total of 749 gross (267 net) wells. We have reduced our drilling and completion costs on operated North Dakota Bakken wells from approximately $9.2 million in 2012 to approximately $8.0 million in 2013. The largest contributors to these cost reductions are multi-well pad development which reduced the overall footprint of our undeveloped acreage were de-risked dueoperations, advancements in stimulation and drilling technology, rig moving and location construction. We exited the year with over 70% of our rig activity on multi-well pads.
Of particular note was the success of our exploration program in the lower layers or “benches” of the Three Forks formation which demonstrated that wells completed in the Lower Three Forks reservoirs may be productive over an area at least 3,800 square miles in size, adding potential incremental recoverable reserves to the
record-breakingBakken field. We also had success expanding the field extents onto our undeveloped leasehold through our step-out drilling
activity in North Dakota. Our Bakken field production averaged 43,148 net Boe per dayprogram and we completed the first of four pilot density projects initiated during the
monthyear. These pilot density projects are designed to help us determine the optimum drilling and spacing pattern for future development of
December 2011, up 69%the Bakken and Three Forks reservoirs. We also initiated a pilot secondary recovery project to evaluate the potential for increasing the ultimate recovery of crude oil from
our average daily Bakken field production in December 2010. Total proved Bakken field reserves at December 31, 2011 were 294 MMBoe, up 49% over our proved Bakken field reserves as of December 31, 2010. Our net acreage position in the Bakken field
increased 7% during 2011, from 855,936 net acres asthrough secondary injection methods. Progress of
December 31 2010 to 915,863 net acres as of December 31, 2011. Approximately 34% of our net acreagethese pilot projects is
developed and 66% of our net acreage is undeveloped as of December 31, 2011.ongoing.
We plan to invest approximately
$1,040.7 million$2.5 billion drilling
488870 gross
(126.2(287 net) wells in the Bakken field during
2012. Approximately 91% will2014, of which approximately 84% is expected to be invested in North Dakota and the remaining
9% will be invested16% in Montana. We plan to
average 24exit 2014 with 23 rigs drilling in the Bakken field
throughout the year, with
2119 rigs located in North Dakota and
34 rigs in Montana.
North Dakota Bakken.Bakken
Our production and reserve growth in the Bakken field during 20112013 came primarily from our activities in North Dakota. Production increased to an average rate of 37,177 net80,374 Boe per day during the month ofthree months ended December 2011,31, 2013, up 78% from36% over the average daily rate in December 2010.2012 fourth quarter. Proved reserves grew 62%increased 33% year-over-year to 256689 MMBoe as of December 31, 2011.2013. Our estimated average ultimate recoverable reserves per well (1,280-acre spacing) also increased during the year from 518 MBoe gross to 603 MBoe gross based on historical well performance. As of December 31, 2011, our North Dakota Bakken properties represented 54%65% of our PV-10 at December 31, 2013and 47%56% of our average daily Boe production for the three months ended December 31, 2011. We2013. In 2013, we completed 369678 gross (109.5(211 net) wells, during 2011, bringing our total number of wells drilled in the North Dakota Bakken to 8492,267 gross (260.8(788 net) wells as of December 31, 2011.2013. As of December 31, 2011,2013, we had 1,313,0571,405,576 gross (663,237(909,052 net) acres in the North Dakota Bakken field, of which 36%58% of the net acreage is developed and 64% of the net acreageremaining 42% is undeveloped. Our inventory of proved net undeveloped locations stood at 1,0501,904 gross (442.4(1,074 net) wells as of December 31, 2011.2013.One of the more significant outcomes of our 2011
Our 2013 drilling activity in the North Dakota Bakken wasfocused on (1) developing our derisked areas, (2) expanding the discoveryfield vertically and horizontally through step-out exploration drilling and (3) pilot density drilling to determine optimum well spacing and pattern for full field development. We successfully achieved our 2013 objectives in each of three additional layers or “benches”these areas and expect to continue making progress with these initiatives in 2014.
Our exploration drilling in North Dakota focused primarily on evaluating the productivity of oil bearing rock inthe Lower Three Forks "benches" which include the Three Forks formation based on six2 ("TF2"), Three Forks 3 ("TF3"), and the Three Forks 4 ("TF4") reservoirs. These benches are layers of dolomite reservoir rock that underlie the proven producing Upper Three Forks bench known as the Three Forks 1 ("TF1"). Core work we completed over a year ago showed that these Lower Three Forks benches contained crude oil but it was unknown if they would produce crude oil at economic rates. During 2013, we successfully conducted a 24 well exploration drilling cores takenprogram to test these Lower Three Forks benches and completed 13 gross (9.5 net) wells in the TF2, 9 gross (7.2 net) wells in the TF3 and 2 gross (1.6 net) wells in the TF4. Results demonstrated that wells completed in the TF2 and TF3 are capable of producing crude oil at various locationsrates comparable to the TF1 across an area over 3,800 square miles in size. This discovery is significant as these results suggest the TF2 and TF3 reservoirs may add incremental recoverable reserves to the Bakken field. Results from the TF4 wells are being evaluated to determine their productive capabilities. At December 31, 2013, we have recorded approximately 20 MMBoe of proved reserves associated with the TF2 and TF3 benches in North Dakota Bakken field. This discovery redefinedBakken.
To further assess the incremental reserve potential of the Lower Three Forks reservoirs and determine the optimum drilling density and pattern to maximize crude oil recovery from the Bakken petroleum systemfield, we initiated four pilot density drilling projects during 2013. A total of 44 wells were drilled in these four projects during 2013. The first of the four pilot density projects to be completed and promptedput into production was our Hawkinson unit. It was the NDICfirst 1,280-acre unit that was fully developed on 320-acre spacing in the Bakken field and included four Middle Bakken wells, three TF1 wells, four TF2 wells and three TF3 wells. These 14 wells produced at a maximum combined initial 24 hour production rate of 14,850 barrels of oil equivalent per day. The Hawkinson density pilot employed several state of the art technologies including the largest downhole microseismic monitoring survey ever conducted in the world. All of this was done to expandhelp us determine the definitionbest inter-well spacing and pattern for future development of the Bakken reservoir,field. We are currently monitoring production from the Hawkinson unit and
incorporating the microseismic and technical data to assess performance. We also completed drilling operations on three additional pilot density projects in certain areas2013 - the Tangsrud, Rollefstad, and Wahpeton projects - which we expect to begin producing during the first half of 2014. The Tangsrud and Rollefstad projects, like the field, to include all zones from 50 feet aboveHawkinson project, are developing the top of theMiddle Bakken Formation down to the baseand first three benches of the Three Forks Formation. These three benches are found approximately 50 to 150 feet belowon 320-acre spacing while the traditional Middle Bakken and Upper (first bench) Three Forks reservoir and indicate that more oil exists under our leasehold than previously perceived. This, in turn, could translate into increased recoverable reserves from our acreage. To prove these three benches add reserves will require additional drilling. Wahpeton project is developing the same zones on 160-acre spacing.
In
October 2011, we successfully drilled and completed our first well in the second bench of the Three Forks formation. The Charlotte 2-22H was completed flowing 1,396 Boe per day from the second bench of the Three Forks and is producing in line with a typical commercial first bench Three Forks producing well.Another significant achievement during 2011 was the successful expansion of the play west of the Nesson anticline. During the year we drilled 80 gross (49.3 net) wells west of the anticline and as of February 15, 2012 had 10 rigs drilling in this area. We also continued to expand the use of our ECO-PadTM technology during the year. ECO-Pad technology allows 4 wells (2 in the Bakken Formation and 2 in the Three Forks Formation) to be drilled from a single drilling pad, which reduces drilling costs, completion costs and environmental impact by centralizing operations on a single pad. Drilling costs are reduced by utilizing a walking rig, which moves between wells on hydraulic feet that eliminate the need to break down the rig each time it moves from one well to another well. Completion costs are reduced by conducting fracture stimulation treatments on multiple wells in one continuous operation. Centralizing operations and production facilities reduces the size of the pad needed by as much as 75%. As of December 31, 2011, we had completed 12 ECO-Pad locations and had 4 ECO-Pad rigs drilling or completing wells. We believe our ECO-Pad technology is a key to maximizing the development of the Bakken field, and we plan to increase the use of this technology as the field matures. During the year, our access to natural gas pipeline infrastructure also improved significantly. At this time, the majority of the natural gas from our wells is connected to pipeline systems.
During 2011, we increased our standard number of fracture stimulation stages per well from approximately 24 stages to 30 stages. Although there are always overriding geologic factors that influence production, we believe the increase in our estimated average recoverable reserves per well from 518 MBoe gross to 603 MBoe gross in 2011 can be attributed primarily to the increased number of fracture stimulation stages used per well. We continually monitor results and modify our fracture stimulation techniques to maximize the amount of crude oil we recover from the reservoirs.
During 2012,2014, we plan to invest approximately $950 million$2.1 billion drilling 470802 gross (114.6(240 net) wells in the North Dakota Bakken field. TheBakken. Approximately 13% of the capital expenditures will be spent on exploratory drilling which will include additional step-out drilling and three new pilot density projects. These new pilot density projects will further test the development of the Middle Bakken and first three benches of the Three Forks on 160-acre spacing. The remainder of the capital is expected to be spent drilling development wells alongin the field including our Nesson Anticline acreagefull field development program in the Antelope prospect in McKenzie and step-out wells westWilliams Counties of the Nesson Anticline to continue expanding the extents of the Bakken and Three Forks reservoirs underlying our acreage. The majority of ourNorth Dakota. This development drilling will be on 1,280-acre spacing but will include some 640-acre infield locations and dual zone development. In time, we expect the North Dakota Bakken field
will eventually be developed on 320-acre spacing like the Elm Coulee field in Montana.done using ECO-Pad technology. As of February 15, 2012,December 31, 2013, we had 1916 operated rigs drilling in the North Dakota Bakken and plan to operate 21 rigs drilling in the play through most of 2012.
exit 2014 at 19 rigs.
Montana Bakken.
Our Montana Bakken
production isproperties are located primarily
inwithin the Elm Coulee field in Richland County, Montana.
The Elm Coulee field was listed byProduction from our Montana Bakken properties reached an all time high during the
Energy Information Administration in 2010 asthree months ended December 31, 2013, averaging 12,961 Boe per day over that period, up 52% from the
17th largest onshore field inaverage daily rate for the lower 48 statesthree months ended December 31, 2012. This reflects the success of the United States ranked by 2009 proved liquid reserves.our ongoing drilling program to optimize and expand our Montana Bakken properties. During 20112013, we completed 2171 gross (12.8(56 net) wells in Montana bringing our total number of wells drilled in the Montana Bakken to 193369 gross (122.1(237 net) wells as of December 31, 2011. Our production increased to an average rate of 5,971 net Boe per day during the month of December 2011, up 26% from the average daily rate in December 2010.2013. As of December 31, 20112013 our Montana Bakken properties represented 9%7% of our PV-10 and 8%9% of our average daily Boe production for the three months ended December 31, 2011. During the year we added 36,278 gross (20,339 net) acres in the Montana Bakken play.2013. As of December 31, 2011,2013, we owned 347,790had 374,301 gross (252,626(300,769 net) acres in Montana Bakken, of which 30%45% of the net acreage is developed and the remaining 70%55% is undeveloped. As of the net acreage is undeveloped.2011 was a breakthrough year for usDecember 31, 2013, we had 60 gross (45 net) proved undeveloped locations identified in the Montana Bakken asfield.
In 2014, we
successfully began to expand and develop the Elm Coulee field using state of the art drilling and completion technology. Areas once considered non-commercial based on old open hole completion technology have now proved to be commercial using cased hole, multi-stage fracture stimulation technology. During 2011 we completed 15 gross (12.3 net) wells in the immediate Elm Coulee field area. These wells included in-field, step-out and strategic exploratory wells that were completed flowing at initial 24 hour rates of up to 1,163 Boe per day. Based on the 2011 drilling program, the productive limits of the Elm Coulee field were expanded 2 to 5 miles to the north onto portions of our undeveloped leasehold.We plan to invest approximately $90.7$412 million drilling 1868 gross (11.6(47 net) wells in the Montana Bakken during 2012.Bakken. Our drilling will focus on in-fieldadditional infill development of Elm Coulee and continued expansion of the Elm Coulee field onto our undeveloped acreage north of the field. As of February 15, 2012,December 31, 2013, we had 34 rigs drillingoperating in the Montana Bakken and plan to maintain 3 rigs inexit 2014 with the play through mostsame number of 2012. As of December 31, 2011, we had 81 gross (50.0 net) proved undeveloped locations identified in the Montana Bakken.
rigs.
The
8 units comprising the Red River units are
comprised of nine units located along the Cedar Creek Anticline in North Dakota, South Dakota and Montana
andthat produce crude oil and natural gas from the Red River “B” formation, a thin continuous, dolomite formation at depths of 8,000 to 9,500 feet. Our
principal producing properties in the Red River units include the Cedar Hills units in North Dakota and Montana, the Medicine Pole Hills units in North Dakota, and the Buffalo Red River units in South Dakota. Our properties in the Red River units comprise a portion of the Cedar Hills field, which was listed by the
U.S. Energy Information Administration in 2010 as the 9th largest onshore field in the lower 48 states of the United States ranked by 2009
proved liquid
proved reserves.
Our
All combined, our Red River units and adjacent areas represented 22%10% of our PV-10 as of December 31, 20112013 and 20% of our average daily Boe production for the three months ended December 2011. Production from these legacy properties increased 5% in 2011 compared to 2010 due to new wells being completed and enhanced recovery techniques being successfully applied. For the month of December 2011, total production from the units averaged 14,925 Boe per day, an increase of 9% from average daily production in December 2010. Proved reserves grew 18% year-over-year to 64 MMBoe as of December 31, 2011. We are continuing to extend the peak performance life of our properties in the Red River units primarily by increasing our water and air injection capabilities and taking other measures to optimize production. As of December 31, 2011, we had 150,534 gross (131,428 net) acres in the Red River units, all of which is developed acreage.In 2012, we plan to complete pattern drilling on the waterflood project in the Cedar Hills units and continue development activity in the Medicine Pole Hills units and Buffalo units. We have allocated $48.5 million of our 2012 capital expenditure budget to the Red River units, which will support one drilling rig and continued investment in facilities and infrastructure.
Cedar Hills Units. The Cedar Hills North unit (“CHNU”) is located in Bowman and Slope Counties, North Dakota. We drilled the initial horizontal well in CHNU, the Ponderosa 1-15, in April 1995. As of December 31, 2011, we had drilled 238 horizontal wells within this 49,700-acre unit, with 117 producing wellbores and the remainder serving as injection wellbores. We own and operate a 96% working interest in the CHNU.
The Cedar Hills West unit (“CHWU”), in Fallon County, Montana, is contiguous to the northern portion of CHNU. As of December 31, 2011, this 7,800-acre unit contained 12 horizontal producing wells and 5 horizontal injection wells. We own and operate a 100% working interest in the CHWU.
In January 2003, we commenced enhanced recovery in the two Cedar Hills units, with high-pressure air injection used throughout most of the area and water injected generally along the boundary of CHNU. Under HPAI, compressed air injected into a reservoir oxidizes residual crude oil and produces flue gases (primarily carbon dioxide and nitrogen) that mobilize and sweep the crude oil into producing wellbores. During February 2008, we began to transition the units to full scale water injection and this transition was completed in June of 2010 when we stopped our air injection at Cedar Hills after injecting nearly 80 Bcf of air into the reservoir. We have seen continued success from our increased density drilling program which supported the idea that it is more economical to inject water than air in these units. In response to our enhanced recovery and increased drilling efforts, our net daily production increased from 2,185 Boe per day in November 2003 to 11,401 Boe per day in December 2011. During 2012, we plan to complete the increased density drilling for both producing wells and injection wells. We plan to invest approximately $36.6 million during 2012 for capital workovers, facilities, and the drilling of 12 gross (11.5 net) wells in the Cedar Hills units.
Medicine Pole Hills Units. The three Medicine Pole Hills units (“MPHU”), consisting of the original MPHU, West MPHU, and South MPHU, are approximately five miles east of the southern portion of the CHNU and are located in Bowman County, North Dakota. We acquired the original Medicine Pole Hills unit in 1995. At that time, the 9,600-acre unit consisted of 18 vertical producing wellbores and 4 injection wellbores under HPAI producing 525 net Bbls of crude oil per day. We have since drilled 51 horizontal wellbores extending production to the west with the formation of the 15,000-acre Medicine Pole Hills West unit and to the south with the 11,500-acre Medicine Pole Hills South unit. All three units are under HPAI and we own and operate working interests of 62%, 92%, and 98% in the original MPHU, West MPHU, and South MPHU, respectively. Total production from the three units averaged 1,787 Boe per day during December 2011, 17% higher than average daily production in December 2010. In 2012, we plan to install a third electric driven air compressor (15 MMcf per day injection capacity) to replace the four remaining higher maintenance gas driven air compressors. We plan to invest approximately $6.4 million during 2012 for drilling, capital workovers, upgrading facilities, and other activities in the Medicine Pole Hills units.
Buffalo Red River Units. Three contiguous Buffalo Red River units (Buffalo, West Buffalo, and South Buffalo) are located in Harding County, South Dakota, approximately 21 miles south of MPHU. We own and operate working interests of 97%, 97%, and 96% in the 33,000 acres comprising the Buffalo, West Buffalo, and South Buffalo units, respectively. When we purchased the three units in 1995, there were 73 vertical producing wellbores and 38 injection wellbores under HPAI producing approximately 1,906 net Bbls of crude oil per day. From 2005 through 2011, we re-entered 46 existing vertical wells and drilled horizontal laterals to increase production and sweep efficiency from the three units. Total production from the three units for the month of December 2011 averaged 1,737 Boe per day, an increase of 22% from average daily production in December 2010. In 2012, we plan to invest approximately $5.5 million for capital workovers, upgrading facilities, and other activities in the Buffalo Red River units.
Niobrara
The Upper Cretaceous Niobrara formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region including the DJ Basin of Colorado and Wyoming. As with most resource plays, the Niobrara has a history of producing through conventional technology with some of
the earliest production dating back to the early 1900s. Individual fields have produced up to 12 MMBoe and individual wells have produced up to 2.1 MMBoe. Historically, natural fracturing has played a key role in producing the Niobrara due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in extent. We believe the Niobrara can be produced on a more widespread basis using horizontal multi-stage fracture stimulation technology where the Niobrara is thermally mature.
DJ Basin. The DJ Basin Niobrara play emerged as a potential crude oil resource play in 2010 and attracted a flurry of leasing activity based on drilling results announced early in 2010. Since that time, approximately 161 horizontal Niobrara wells have been reported as completed with initial production rates of up to 1,665 Boe per day. The most consistent results have been reported on the Colorado portion of the DJ Basin, particularly Weld County Colorado. As of December 31, 2011, we owned 154,799 gross (93,339 net) acres in the DJ Basin Niobrara play. Approximately 37% of the net acreage is located in Weld and Morgan Counties, Colorado and 63% in Laramie, Goshen and Platte Counties in Wyoming.
During 2011, we drilled our first horizontal Niobrara wells in the DJ Basin and as of February 15, 2012, we have completed 5 gross (3.6 net) Niobrara wells. Results have varied which is typical in the early stages of any play as we refine our geologic model and completion techniques. Thus far, the Staudinger 1-31H (56% WI) is our best performing well, producing 736 Boe per day during its initial 24 hour test period. Early performance of the Staudinger 1-31H is encouraging and in line with our economic model for the play. Of note, we continue to be a leader with technology as our Staudinger 1-31H and Newton 1-4H wells were the first 1,280-acre unit wells drilled in the play. During 2011 we acquired 92 square miles of 3D seismic data to guide future drilling.
In 2012, we plan to invest approximately $59 million to drill 26 gross (12.0 net) wells in the DJ Basin Niobrara play. This drilling will continue to be focused in Weld County, Colorado. The drilling will include step-out and exploratory wells that are strategically located to de-risk our acreage.
South Region
Our properties in the South region represented 12% of our PV-10 as of December 31, 2011 and 22%10% of our average daily Boe production for the three months ended December 31, 2011. During the three months ended December 31, 2011, our2013. Our average daily production from suchthese legacy properties was 2,316 net Bblsdecreased 2% in the fourth quarter of
2013 compared to the 2012 fourth quarter. The relatively shallow decline in these mature properties is due to optimization efforts and some limited drilling activity. Proved reserves were 77 MMBoe as of December 31, 2013. We are continuing to extend the performance life of our properties in the Red River units primarily by improving our water and air injection efficiency and taking other measures to optimize production. Additional enhanced recovery via carbon dioxide injection is currently being studied. As of December 31, 2013, we had 156,703 gross (137,294 net) acres in the Red River units and adjacent areas, all of which is developed acreage. We have allocated $39 million of our 2014 capital expenditure budget to the Red River units and adjacent areas to support one drilling rig. Additional capital will be used to support injection projects and continued investment in facilities and infrastructure.
North Region Marketing Activities
Crude Oil. We continue to build upon a portfolio approach (rail and pipe) to marketing our crude oil that began in 2008 with our first shipments of crude oil by rail out of the Williston Basin. During 2013, we continued our efforts to shift Bakken crude oil sales to coastal markets in the United States with less dependence on currently available pipeline markets. Rail transportation costs are typically higher than pipeline transportation costs per barrel mile, but market prices realized in U.S. coastal markets continue to be competitive with currently available pipeline markets. We plan to continue pursuing this
portfolio approach to balance volumes delivered to pipeline and 85,631rail market destinations in an effort to maximize net Mcfwellhead value.
Transportation infrastructure continues to improve in the North region with gathering systems picking up crude oil at well site storage tanks with subsequent delivery to railhead or regional pipeline terminals, thereby reducing dependence on truck deliveries. We expect more of natural gas, up 82% from the same period in 2010. Our principal producing propertiesour North region crude oil will be shipped in this region are locatedfashion through the coming years, especially as we accelerate development drilling using ECO-Pad technology.
Natural Gas. Field infrastructure build-out continued in the AnadarkoWilliston Basin in 2013 as third party midstream gathering and Arkoma basins of Oklahoma, as well as various basins of Texasprocessing companies expanded field gathering and Louisiana.Oklahoma Woodford Shale
The Oklahoma Woodford is a widespread unconventional shale reservoir that produces crude oil, natural gascompression facilities, cryogenic processing capacity and natural gas condensateliquids (“NGL”) pipeline and rail capacity to market centers. In 2013, we continued to make notable progress in various basins acrossadhering to our flaring reduction initiatives. For the stateyear ended December 31, 2013, the percentage of Oklahoma. our operated natural gas production flared in North Dakota Bakken was less than 11%, compared to 15% in
2012 and 19% in 2011. We expect to further reduce this amount as we continue to build out infrastructure and transition to a greater use of ECO-Pad development in 2014 and beyond. South Region
Our principal producing properties in the Oklahoma Woodford are located in the Arkoma and Anadarko basins. Combined, these propertiesSouth region represented 11%18% of our PV-10 as of December 31, 20112013 and 18% of our net average daily Boe production for the three months ended December 31, 2011. Production from the Oklahoma Woodford for 2011 totaled 3,548 MBoe (21,288 MMcfe), up 84% over 2010. Production increased throughout the year, and the average daily production for our Oklahoma Woodford properties for the month of December 2011 was 15,026 Boe per day, up 145% over our daily average production for the month of December 2010. As of December 31, 2011, we held 617,313 gross (332,162 net) acres in the play. As of December 2011, 25% of the net acreage is developed and the remaining 75% of the net acreage is undeveloped.During 2011 we completed 121 gross (46.6 net) Oklahoma Woodford wells. During 2012, we plan to invest approximately $356.1 million drilling 160 gross (46.6 net) wells in the Oklahoma Woodford. As of February 15, 2012 we had 12 rigs drilling in the Oklahoma Woodford and plan to operate 10 rigs in the play through most of 2012.
Anadarko Woodford. The Anadarko Woodford represented 9% of our PV-10 as of December 31, 2011 and 13% of our average daily Boe production for the three months ended December 31, 2011. Our Anadarko Woodford2013. For the three months ended December 31, 2013, our average daily production grew 367% year-over-year due to our increased drilling activity in 2011. During the month of December 2011, our Anadarko Woodford production averaged 10,675 netfrom such properties was 35,709 Boe per day, up 465% over our average daily production58% from the same period in December 2010.
Over the past 2 years, the Anadarko Woodford play has developed into an established resource play that appears to cover at least 1,800 square miles (1,152,000 acres) along the eastern flank of the Anadarko Basin. We control one of the largest acreage positions2012. Our principal producing properties in this region are located in the Anadarko Woodfordemerging SCOOP play with 444,345 gross (278,116 net) acres under lease as of December 31, 2011. This acreage isin south-central Oklahoma.
SCOOP
Our SCOOP properties are located in Canadian, Blaine, Dewey, Caddo,southern Oklahoma primarily in Garvin, Grady, Stephens, Carter, McClain and McClain counties in Oklahoma, extending approximately 50 miles northwest and 75 miles southeast from the Cana field area, where the initial discovery was made in late 2007. Approximately 65% of our acreage is located in our Northwest Cana project and 35% is located in our Southeast Cana project.During 2011, we accelerated our drilling program and completed 103 gross (41.8 net) wells as compared to 16 gross (8.2 net) wells in 2010. Our 2011 drilling program was designed to expand the known extents of Anadarko Woodford production on our acreage. Under this program, we successfully completed strategic wells in both our Northwest Cana and Southeast Cana projects and de-risked more of our acreage in the play. In particular, the Lambakis 1-11H (98% WI) and the Lyle 1-30H (99%WI) wells in Southeast Cana established commercial production 30 miles south of the known limit of Woodford production at year-end 2010. Both wells are exceptional wells producing a combination of oil, natural gas and natural gas liquids. The Lambakis 1-11H produced 5.4 MMcf of natural gas and 160 Bbls of crude oil per day during its initial 24 hour test period. The Lyle 1-30H produced 7.1 MMcf of natural gas and 325 Bbls of crude oil per day during its initial 24 hour test period. The high liquids content of the natural gas is significant as it increases the overall value of the production due to the higher BTU content of the natural gas.
In February 2012, we completed the first cross-unit well drilled in the Anadarko Woodford play. The Toms 1-21XH (90% WI) in Blaine County, Oklahoma produced 1.9 MMcf per day and 965 Bbls per day during its initial 24 hour test period. The well was drilled to a total depth of 20,523 feet and included a 9,500 foot lateral, which is approximately twice the length of a typical horizontal Anadarko Woodford well. Cross-unit spaced drilling is significant because it allows operators to access two spacing units from a single long wellbore. From our experience, we expect the longer laterals will reduce costs, increase well productivity and enhance the overall economics of the play. We are very encouraged by the results of our first cross-unit well and expect to increase the use of this technology as we develop the field.
During 2011, we acquired approximately 600 square miles of proprietary 3D seismic data. Acquiring this data was a critical step in the development of the Northwest Cana and Southeast Cana projects as the data will be used to guide our drilling for years to come. Another critical development in 2011 was the increased pipeline capacity to transport natural gas from the Northwest Cana area. Curtailments experienced in 2011 should be eliminated in 2012 as a result of new pipeline infrastructure scheduled for operation in early 2012.
An upside to the Anadarko Woodford is the potential to encounter additional pay from reservoirs overlying the Woodford. With the Anadarko basin being one of the more prolific crude oil and natural gas producing basins in the United States, there are up to 12 conventional reservoirs overlying the Anadarko Woodford shale. All of these conventional reservoirs have the potential to produce locally under our Anadarko Woodford acreage. To date, approximately one third of our Woodford wells have encountered indications of productive reservoirs in overlying Tonkawa, Red Fork, Morrow, Springer and/or Mississippian reservoirs, while drilling to the Woodford shale.
In 2012, we plan to invest approximately $354.5 million to drill 159 gross (46.1 net) wells to further delineate and develop the Anadarko Woodford on our acreage. As of February 15, 2012, we had 12 operated rigs drilling in the Anadarko Woodford play and plan to operate 10 rigs in the play through most of 2012. To support our
drilling program, we expect to invest approximately $11.9 million to acquire approximately 350 square miles of proprietary 3D seismic to guide future drilling on our acreage. As of December 31, 2011, we had a total of 251 gross (120.1 net) proved undeveloped locations identified on our Anadarko Woodford acreage.
Arkoma Woodford. The Arkoma WoodfordLove Counties. SCOOP represented 2%16% of our PV-10 as of December 31, 20112013 and 5%17% of our average daily Boe production for the three months ended December 31, 2011. Year-over-year, Arkoma Woodford2013. For the year ended December 31, 2013, SCOOP production was down 6%grew 318% over 2012 due to our scaled backincreased drilling program in 2011. As of December 31, 2011 we have completed a total of 367 gross (59.7 net) wellsactivity in the Arkoma Woodford play.
In 2011, we slowed our pace of drilling in the Arkoma Woodford as available capital was redirected to the more liquid-rich Anadarko Woodford. During the year we completed a total of 18 gross (4.8 net) wells, as compared to 50 gross (6.5 net) wells in 2010. The wells were focused primarily on our East McAlester acreage and produced up to 5,055 Mcf per day during their initial 24 hour test period. As of December 31, 2011, we owned approximately 132,898 gross (39,594 net) acres in the Arkoma Woodford play, of which 63% of our net acreage is developed and the remaining 37% of our net acreage is undeveloped.
In 2011, we removed 21.9 MMBoe of proved undeveloped reserves from our Arkoma Woodford district, representing 213 gross (44.8 net) PUD locations. We had planned to develop these PUD reserves by year-end 2013. However, given current and projected prices for natural gas, we elected to defer drilling and therefore declassified these PUD reserves. A remaining total of 97 gross (46.5 net) PUD locations, representing 26.0 MMBoe of remaining PUD reserves, have been identified on this acreage as of December 31, 2011. In 2012, we plan to finish wells in progress at year-end 2011 but plan to defer any further drilling until natural gas prices improve. We expect to invest approximately $1.6 million to drill 1 gross (0.5 net) well in the Arkoma Woodford play during 2012.
East Region
Our properties in the East region represented 1% of our PV-10 as of December 31, 2011. During For the three months ended December 31, 2011,
2013, SCOOP production averaged 23,754 Boe per day, up 233% over our average daily production from such properties was 1,178 net Boe per day. Our principal producing properties in this region are located infor the Illinois Basin and Michigan Basin in the eastern United States. We continue to maximize the performance of these properties through workovers, recompletions and drilling as warranted.three months ended December 31, 2012. As of December 31, 2011,2013, we had 69,042held 677,684 gross (49,545(403,854 net) acres under lease in the Trenton-Black River area of Michigan,SCOOP, of which 1%12% of the net acreage iswas developed and 99%the remaining 88% of the net acreage was undeveloped. Our inventory of proved undeveloped drilling locations in SCOOP as of December 31, 2013 totaled 309 gross (153 net) wells. We completed 77 gross (42 net) wells in SCOOP during 2013 and as of December 31, 2013 we had completed a total of 145 gross (79 net) wells in SCOOP. Our 2013 drilling program included exploration, step-out and development wells focused on de-risking the play and holding our acreage by production. The year 2013 was a particularly impactful year for SCOOP as our drilling results and results from others in the industry established both a crude oil and condensate rich, natural gas producing fairway that combined is undeveloped. Drillingapproximately 20 miles wide and 120 miles long. Based on our 2013 drilling results, SCOOP is proving to be another significant asset for the Company with considerable potential for production and reserve growth.
A possible upside to SCOOP is the potential to encounter additional pay from a variety of conventional and potential unconventional reservoirs overlying and underlying the Woodford formation. There are over 60 different conventional reservoirs known to produce in the SCOOP area. These conventional reservoirs have the potential to produce locally under our SCOOP acreage.
In 2014, we plan to invest approximately $865 million to drill 159 gross (72 net) wells in the SCOOP play. Approximately 40% of these properties has been guided bywells will be multi-unit wells. Multi-unit wells enable us to drill two spacing units from one location, which reduces well costs and our overall surface footprint. The 2014 drilling program will continue to focus on expanding the known productive extents of SCOOP and de-risking our acreage. It will also include pilot density projects to determine the optimum well spacing and pattern for full scale development of SCOOP in the future. We also expect to invest approximately $19 million to acquire approximately 230 square miles of additional proprietary 3D seismic data. We currently own 64 square miles of 3D seismic data on the properties and have numerous potential drilling locations identified forto guide future drilling. As of December 31, 2013, we had 18 operated rigs drilling in the SCOOP play.
South Region Marketing Activities
Crude Oil. Due to the proximity of our South region operations to the market center in Cushing, Oklahoma, we typically sell our South region production directly to midstream trading and transportation companies at the wellhead with price realizations that correlate with WTI benchmark pricing. We anticipate continuing this approach through early 2015 and to begin delivery of production from our SCOOP properties via wellhead pipeline gathering and intrastate pipeline systems directly into Cushing as field infrastructure is constructed and developed.
Natural Gas. In 2012,2013, field infrastructure build-out continued at a rapid pace in the Anadarko Basin and in SCOOP as third party midstream gathering and processing companies expanded field gathering and compression facilities, cryogenic processing capacity and NGL pipeline capacity to market centers. Throughout our South region leasehold, we planare coordinating our well completion operations to acquire an additional 30 square miles of 3D seismiccoincide with well connections to identify additional opportunities for drilling.gathering systems in order to minimize greenhouse gas emissions.
Production and Price History
The following table sets forth summary information concerning our production results, average sales prices and production costs for the years ended December 31, 2011, 20102013, 2012 and 20092011 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2011: | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
Net production volumes: | | | | | | | | | | | | |
Crude oil (MBbls) (1) | | | | | | | | | | | | |
North Dakota Bakken | | | 8,480 | | | | 4,450 | | | | 2,257 | |
Anadarko Woodford | | | 267 | | | | 56 | | | | 15 | |
Total Company | | | 16,469 | | | | 11,820 | | | | 10,022 | |
Natural gas (MMcf) | | | | | | | | | | | | |
North Dakota Bakken | | | 7,523 | | | | 3,994 | | | | 1,729 | |
Anadarko Woodford | | | 11,422 | | | | 2,451 | | | | 554 | |
Total Company | | | 36,671 | | | | 23,943 | | | | 21,606 | |
Crude oil equivalents (MBoe) | | | | | | | | | | | | |
Total Company | | | 22,581 | | | | 15,811 | | | | 13,623 | |
Average sales prices: (2) | | | | | | | | | | | | |
Crude oil ($/Bbl) | | | | | | | | | | | | |
North Dakota Bakken | | $ | 88.43 | | | $ | 70.09 | | | $ | 55.06 | |
Anadarko Woodford | | | 92.14 | | | | 77.68 | | | | 60.80 | |
Total Company | | | 88.51 | | | | 70.69 | | | | 54.44 | |
Natural gas ($/Mcf) | | | | | | | | | | | | |
North Dakota Bakken | | | 7.18 | | | | 6.38 | | | | 4.73 | |
Anadarko Woodford | | | 5.27 | | | | 4.63 | | | | 3.95 | |
Total Company | | | 5.24 | | | | 4.49 | | | | 3.22 | |
Crude oil equivalents ($/Boe) | | | | | | | | | | | | |
Total Company | | | 73.05 | | | | 59.70 | | | | 45.10 | |
Costs and expenses: (2) | | | | | | | | | | | | |
Production expenses ($/Boe) | | | | | | | | | | | | |
North Dakota Bakken | | $ | 4.05 | | | $ | 2.94 | | | $ | 3.64 | |
Anadarko Woodford | | | 1.95 | | | | 1.52 | | | | 1.88 | |
Total Company | | | 6.13 | | | | 5.87 | | | | 6.89 | |
Production taxes and other expenses ($/Boe) | | | 6.42 | | | | 4.82 | | | | 3.37 | |
General and administrative expenses ($/Boe) (3) | | | 3.23 | | | | 3.09 | | | | 3.03 | |
DD&A expense ($/Boe) | | | 17.33 | | | | 15.33 | | | | 15.34 | |
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| Net production volumes: | | | | | | |
| Crude oil (MBbls) (1) | | | | | | |
| North Dakota Bakken | | 23,513 |
| | 15,936 |
| | 8,480 |
|
| SCOOP | | 2,004 |
| | 478 |
| | 96 |
|
| Total Company | | 34,989 |
| | 25,070 |
| | 16,469 |
|
| Natural gas (MMcf) | | | | | | |
| North Dakota Bakken | | 26,783 |
| | 16,454 |
| | 7,523 |
|
| SCOOP | | 29,438 |
| | 7,060 |
| | 1,927 |
|
| Total Company | | 87,730 |
| | 63,875 |
| | 36,671 |
|
| Crude oil equivalents (MBoe) | | | | | | |
| North Dakota Bakken | | 27,977 |
| | 18,679 |
| | 9,733 |
|
| SCOOP | | 6,910 |
| | 1,654 |
| | 417 |
|
| Total Company | | 49,610 |
| | 35,716 |
| | 22,581 |
|
| Average sales prices: (2) | | | | | | |
| Crude oil ($/Bbl) | | | | | | |
| North Dakota Bakken | | $ | 89.45 |
| | $ | 84.50 |
| | $ | 88.43 |
|
| SCOOP | | 95.63 |
| | 89.37 |
| | 93.02 |
|
| Total Company | | 89.93 |
| | 84.59 |
| | 88.51 |
|
| Natural gas ($/Mcf) | | | | | | |
| North Dakota Bakken | | $ | 6.26 |
| | $ | 5.55 |
| | $ | 7.18 |
|
| SCOOP | | 5.59 |
| | 4.01 |
| | 7.56 |
|
| Total Company | | 5.25 |
| | 4.20 |
| | 5.24 |
|
| Crude oil equivalents ($/Boe) | | | | | | |
| North Dakota Bakken | | $ | 81.17 |
| | $ | 76.95 |
| | $ | 82.56 |
|
| SCOOP | | 51.55 |
| | 34.01 |
| | 56.30 |
|
| Total Company | | 72.71 |
| | 66.83 |
| | 73.05 |
|
| Average costs per Boe: (2) | | | | | | |
| Production expenses ($/Boe) | | | | | | |
| North Dakota Bakken | | $ | 5.50 |
| | $ | 4.31 |
| | $ | 4.05 |
|
| SCOOP | | 0.99 |
| | 1.02 |
| | 1.30 |
|
| Total Company | | 5.69 |
| | 5.49 |
| | 6.13 |
|
| Production taxes and other expenses ($/Boe) | | $ | 6.69 |
| | $ | 6.42 |
| | $ | 6.42 |
|
| General and administrative expenses ($/Boe) (3) | | $ | 2.91 |
| | $ | 3.42 |
| | $ | 3.23 |
|
| DD&A expense ($/Boe) | | $ | 19.47 |
| | $ | 19.44 |
| | $ | 17.33 |
|
| |
| (1) | Crude oil sales volumes differ from production volumes because, at various times, we have stored crude oil in inventory due to pipeline line fill requirements, low commodity prices, or transportation constraints or we have sold crude oil from inventory. Crude oil sales volumes were 304 MBbls less than production volumes for the year ended December 31, 2011, 78 MBbls more than production volumes for the year ended December 31, 2010 and 82 MBbls less than production volumes for the year ended December 31, 2009.2013, |
112 MBbls less than production volumes for the year ended December 31, 2012 and 30 MBbls less than production volumes for the year ended December 31, 2011.
| |
| (2) | Average sales prices and per unit costs have been calculated using sales volumes and exclude any effect of derivative transactions. |
| |
| (3) | General and administrative expense ($/Boe) includes non-cash equity compensation expenseexpenses of $0.73$0.80 per Boe, $0.74$0.82 per Boe, and $0.84$0.73 per Boe for the years ended December 31, 2013, 2012 and 2011, 2010respectively, and 2009,corporate relocation expenses of $0.04 per Boe, $0.22 per Boe and $0.14 per Boe for the years ended December 31, 2013, 2012, and 2011, respectively. |
The following table sets forth information regarding our average daily production by region during the fourth quarter of 2011: | | | | | | | | | | | | |
| | | Fourth Quarter 2011 Daily Production | |
| | | Crude Oil
(Bbls per day) | | | Natural Gas
(Mcf per day) | | | Total
(Boe per day) | |
North Region: | | | | | | | | | | | | |
Bakken field | | | | | | | | | | | | |
North Dakota Bakken | | | 30,691 | | | | 29,245 | | | | 35,565 | |
Montana Bakken | | | 4,884 | | | | 4,764 | | | | 5,678 | |
Red River units | | | | | | | | | | | | |
Cedar Hills | | | 11,276 | | | | 3,048 | | | | 11,784 | |
Other Red River units | | | 3,070 | | | | 2,352 | | | | 3,462 | |
Other | | | 608 | | | | 2,136 | | | | 964 | |
South Region: | | | | | | | | | | | | |
Oklahoma Woodford | | | | | | | | | | | | |
Anadarko Woodford | | | 1,414 | | | | 50,437 | | | | 9,820 | |
Arkoma Woodford | | | 21 | | | | 22,004 | | | | 3,688 | |
Other | | | 881 | | | | 13,190 | | | | 3,080 | |
East Region | | | 1,060 | | | | 707 | | | | 1,178 | |
| | | | | | | | | | | | |
Total | | | 53,905 | | | | 127,883 | | | | 75,219 | |
2013:
|
| | | | | | | | | |
| | | Fourth Quarter 2013 Daily Production |
| | | Crude Oil
(Bbls per day) | | Natural Gas
(Mcf per day) | | Total
(Boe per day) |
| North Region: | | | | | | |
| Bakken field | | | | | | |
| North Dakota Bakken | | 67,164 |
| | 79,263 |
| | 80,374 |
|
| Montana Bakken | | 11,422 |
| | 9,237 |
| | 12,961 |
|
| Red River units | | | | | | |
| Cedar Hills | | 10,101 |
| | 2,382 |
| | 10,498 |
|
| Other Red River units | | 3,468 |
| | 2,592 |
| | 3,900 |
|
| Other | | 367 |
| | 2,672 |
| | 812 |
|
| South Region: | | | | | | |
| SCOOP | | 6,567 |
| | 103,121 |
| | 23,754 |
|
| Northwest Cana | | 542 |
| | 36,920 |
| | 6,696 |
|
| Arkoma Woodford | | 4 |
| | 16,594 |
| | 2,769 |
|
| Other | | 808 |
| | 10,085 |
| | 2,490 |
|
| Total | | 100,443 |
| | 262,866 |
| | 144,254 |
|
Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interests owned in gross wells. The following table presents the total gross and net productive wells by region and by crude oil or natural gas completion as of December 31, 2011: | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Crude Oil Wells | | | Natural Gas Wells | | | Total Wells | |
| | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
North Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Bakken field | | | | | | | | | | | | | | | | | | | | | | | | |
North Dakota Bakken | | | 884 | | | | 291 | | | | 6 | | | | 1 | | | | 890 | | | | 292 | |
Montana Bakken | | | 216 | | | | 137 | | | | 2 | | | | 1 | | | | 218 | | | | 138 | |
Red River units | | | 267 | | | | 242 | | | | 2 | | | | 2 | | | | 269 | | | | 244 | |
Other | | | 227 | | | | 209 | | | | 6 | | | | 2 | | | | 233 | | | | 211 | |
South Region: | | | | | | | | | | | | | | | | | | | | | | | | |
Oklahoma Woodford | | | | | | | | | | | | | | | | | | | | | | | | |
Anadarko Woodford | | | 12 | | | | 7 | | | | 119 | | | | 49 | | | | 131 | | | | 56 | |
Arkoma Woodford | | | — | | | | — | | | | 387 | | | | 57 | | | | 387 | | | | 57 | |
Other | | | 220 | | | | 173 | | | | 249 | | | | 124 | | | | 469 | | | | 297 | |
East Region | | | 645 | | | | 519 | | | | 13 | | | | 11 | | | | 658 | | | | 530 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 2,471 | | | | 1,578 | | | | 784 | | | | 247 | | | | 3,255 | | | | 1,825 | |
2013:
|
| | | | | | | | | | | | | | | | | | |
| | | Crude Oil Wells | | Natural Gas Wells | | Total Wells |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| North Region: | | | | | | | | | | | | |
| Bakken field | | | | | | | | | | | | |
| North Dakota Bakken | | 2,261 |
| | 778 |
| | 6 |
| | 1 |
| | 2,267 |
| | 779 |
|
| Montana Bakken | | 361 |
| | 232 |
| | 2 |
| | 1 |
| | 363 |
| | 233 |
|
| Red River units | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Cedar Hills | | 136 |
| | 130 |
| | — |
| | — |
| | 136 |
| | 130 |
|
| Other Red River units | | 145 |
| | 131 |
| | — |
| | — |
| | 145 |
| | 131 |
|
| Other | | 33 |
| | 15 |
| | 4 |
| | 1 |
| | 37 |
| | 16 |
|
| South Region: | | | | | | | | | | | |
|
| SCOOP | | 45 |
| | 23 |
| | 96 |
| | 51 |
| | 141 |
| | 74 |
|
| Northwest Cana | | 11 |
| | 6 |
| | 157 |
| | 67 |
| | 168 |
| | 73 |
|
| Arkoma Woodford | | 3 |
| | — |
| | 397 |
| | 59 |
| | 400 |
| | 59 |
|
| Other | | 208 |
| | 162 |
| | 232 |
| | 115 |
| | 440 |
| | 277 |
|
| Total | | 3,203 |
| | 1,477 |
| | 894 |
| | 295 |
| | 4,097 |
| | 1,772 |
|
As of December 31,
2011,2013, we did not own interests in any wells containing multiple completions.
As is customary in the crude oil and natural gas industry, we initially conduct only a cursory reviewupon initiation of title to our properties onfee leasing of undeveloped leasehold which we dodoes not have associated proved reserves. reserves, contract landmen conduct a title examination of courthouse records. Such title examinations are reviewed and approved by Company landmen. Prior to closing an acquisition from a third party, whether producing crude oil and natural gas leases or non-producing, Company and contract landmen perform title examinations at applicable courthouses and examine the seller's internal land, legal, well, marketing and accounting records including existing title opinions. We may procure an acquisition title opinion depending on the materiality of the properties involved.
Prior to the commencement of drilling operations on those properties,any property, we endeavor to conductprocure a thorough title examinationopinion from external legal counsel and perform curative work with respectnecessary to significantsatisfy requirements pertaining to material title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.
We have
obtainedprocured and cured title opinions on
substantially all of our producing properties and believe we have satisfactorydefensible title to our producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. Prior to completing an acquisition of producing crude oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our crude oil and natural gas properties are subject to customary royalty and other interests liens to secure borrowings under our revolving credit facility, liens for current taxes and other burdens which we believe do not materially interfere with the use of the properties or affect our carrying value of such properties.
Marketing and Major Customers
Most of our crude oil production is sold to end users at major market centers. Other production
not sold at major market centers is sold to select midstream marketing companies or crude oil refining companies at the lease. We have significant production directly connected to pipeline gathering systems,
althoughwith the
remaining balance of our production
isbeing transported by truck or rail. Where
directly marketed crude oil
that is directly marketed is transported by truck,
the crude oilit is delivered to the most practical point on a pipeline system for delivery to a sales point “downstream” on another connecting pipeline. Crude oil sold at the lease is delivered directly onto the
purchasers’purchaser’s truck and the sale is complete at that point.
As a result of pipeline constraints,
and the continuous increase in Williston Basin production,
and our desire to transport our crude oil to U.S. coastal markets which provide favorable pricing, in December
20112013 we transported approximately
30%70% of
theour operated crude oil production from our North region by rail. We are using both manifest and unit train facilities for these shipments and anticipate these shipments will continue.
We have a strategic mix of gas transport, processing and sales arrangements for our natural gas production. Our natural gas production is sold at various points along the market chain from wellhead to points downstream under monthly interruptible packaged-volume deals, short-term seasonal packages, and long-term multi-year acreage dedication type contracts. All of our natural gas is sold at
market, based on published pricing.market. Some of our contracts allow us the flexibility to sell at the well or, with notice, take our gas “in-kind”, transport, process, and sell in the market area. Midstream natural gas gathering and processing companies are our primary transporters and purchasers.
Our marketing of crude oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, seePart I, Item 1A. Risk factors—Our business depends on crude oil and natural gas transportation facilities, most of which are owned by third parties, and on the availability of rail transportation. For the years ended December 31,
2011, 20102013, 2012 and
2009, crude oil2011, sales to Marathon Crude Oil Company accounted for approximately
41%12%,
57%21% and
56%41% of our total
crude oil and natural gas revenues, respectively.
Sales to United Energy Trading accounted for approximately 11% of our total crude oil and natural gas revenues for both of the years ended December 31, 2013 and 2012. Additionally, sales to Tesoro Refining and Marketing Company accounted for approximately 15% of our total crude oil and natural gas revenues for the year ended December 31, 2013. No other
purchaserpurchasers accounted for more than 10% of our total crude oil and natural gas
salesrevenues for
2011, 20102013, 2012 and
2009.2011. We believe the loss of our largest purchaser would not have a material adverse effect on our operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in our producing regions.
We operate in a highly competitive environment for acquiring properties, marketing crude oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel
resources permit. In addition, shortages or the high cost of drilling rigs, equipment or other services could delay or adversely affect our development and exploration operations. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry.
Regulation of the Crude Oil and Natural Gas Industry
All of our operations are conducted onshore in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations,
policies, and
other policy implementationsinterpretations affecting
the crude oil and natural gasour industry have been pervasive and are continuously reviewed
for modification,by legislators and regulators, including the imposition of new or increased requirements on us and other industry participants. Applicable laws and regulations
and other requirements affecting our industry and its members often carry substantial penalties for failure to comply. Such
laws and regulationsrequirements may have a significant effect on the exploration, development, production and sale of crude oil and natural gas. These
laws and regulationsrequirements increase the cost of doing business and, consequently, affect profitability. We believe we are in substantial compliance with all laws and regulations
and policies currently applicable to our operations and our continued compliance with existing requirements will not have a material adverse impact on us. However, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws and regulations may be amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. We do not expect any future legislative or regulatory initiatives will affect our operations in a manner materially different than they would affect our similarly situated competitors.
Following is a discussion of significant laws and regulations that may affect us in the areas in which we operate.
Regulation of
Sales sales andTransportation transportation of Crude Oilcrude oil and Natural Gas Liquidsnatural gas liquids
Sales of crude oil and natural gas liquids or condensate
(“NGLs”)in the United States are not currently
regulatedsubject to price controls and are made at negotiated prices. Nevertheless, the U.S. Congress could enact price controls in the future.
The United States does regulate the exportation of petroleum and petroleum products, and these regulations could restrict the markets for these commodities and thus affect sales prices. With regard to our physical sales of crude oil and derivative instruments relating to crude oil, we are required to comply with anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”). See the discussion below of “Other Federal Laws and Regulations Affecting Our
Industry.Industry—FTC and CFTC Market Manipulation Rules.” Should we violate the anti-market manipulation laws and regulations, we could be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Our sales of crude oil are affected by the availability, terms and costs of transportation. The transportation of crude oil and NGLs, as well as other liquid products, is subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate crude oil and NGL pipeline transportation rates under the Interstate Commerce
Act.Act and the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. In general,
such pipeline rates must be
just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. Oil and other liquid pipeline rates are often cost-based, although many pipeline charges
today are
today based on historical rates adjusted for inflation and other factors, and other charges may result from settlement rates agreed to by all shippers or market-based rates, which are permitted in certain circumstances.
FERC or interested persons may challenge existing or changed rates or services. Intrastate crude oil and NGL pipeline transportation rates may be subject to regulation by state regulatory commissions. The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as the interstate and intrastate transportation rates
that we pay are generally applicable to all comparable shippers, we believe the regulation of intrastate transportation rates will not affect our operations in a way that materially differs from the effect on the operations of our competitors who are similarly situated.
Further, interstate pipelines and intrastate common carrier pipelines must provide service on an equitable basis. Under this standard, such pipelines must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When such pipelines operate at full capacity, access is governed by prorating provisions,
which may be set forth in the pipelines’ published tariffs.
Accordingly, weWe believe we generally will have access to crude oil pipeline transportation services to the same extent as
to our similarly situated competitors.
A portion of our North region crude oil production is shipped to market centers using rail transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s (“U.S. DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relating to crude-by-rail transportation. In addition, third party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the U.S. DOT, the Federal Railroad Administration (“FRA”) of the DOT, OSHA, as well as other federal regulatory agencies. Additionally, various state and local
agencies have jurisdiction over disposal of hazardous waste and seek to regulate movement of hazardous materials in ways not preempted by federal law.
In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of 2008, which implemented regulations governing different areas related to railroad safety. Recently, in response to train derailments occurring in the United States and Canada in 2013, U.S. regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the National Transportation Safety Board (“NTSB”) issued a series of recommendations to the FRA and PHMSA to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) to develop an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity of product carried on a train, and (iii) to audit shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the U.S. Department of Transportation issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of petroleum crude oil be handled as a Packing Group I or II hazardous material.
We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows. At this time, it is not possible to estimate the potential impact on our business if new federal or state rail transportation regulations are enacted.
Regulation of
Salessales and
Transportationtransportation of
Natural Gasnatural gas
In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural
gas effective January 1, 1993.gas. The FERC, which has the authority under the Natural Gas Act (“NGA”) to regulate prices, terms, and conditions for the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. However, either the U.S. Congress or the FERC (with respect to the resale of gas in interstate commerce) could re-impose price controls in the future.
The U.S. Department of Energy (“U.S. DOE”) regulates the terms and conditions for the exportation and importation of natural gas (including liquefied natural gas or “LNG”). U.S. law provides for very limited regulation of exports to and imports from any country that has entered into a Free Trade Agreement (“FTA”) with the United States that provides for national treatment of trade in natural gas; however, the U.S. DOE’s regulation of imports and exports from and to countries without such FTAs is more comprehensive. The FERC also regulates the construction and operation of import and export facilities, including LNG terminals. Regulation of imports and exports and related facilities may materially affect natural gas markets and sales prices.
The FERC regulates interstate natural gas transportation rates and service conditions under the NGA and the Natural Gas Policy Act of 1978 (“NGPA”), which affects the marketing of natural gas we produce, as well as revenues we receive for sales of our natural gas. The FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.
Beginning in 1992, theThe FERC
has issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage services on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. We cannot provide any assurance that the
less stringentpro-competitive regulatory approach established by the FERC will continue. However, we do not believe any action taken will affect us in a materially different way than other natural gas producers.
With regard to our physical sales of natural gas and derivative instruments relating to natural gas, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and the CFTC. See the discussion below of “Other Federal Laws and Regulations Affecting Our
Industry.Industry—FTC and CFTC Market Manipulation Rules.” Should we violate the anti-market manipulation laws and regulations, we could be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to various FERC orders,we may be required to submit reports to the FERC for some of our operations. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency and Reporting Rules.”
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policies on gathering systems have varied in the past, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances,
nondiscriminatoryequitable take requirements. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels in the future. We cannot predict what effect, if any, such changes
mightmay have on our operations, but the natural gas industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory
changes.changes, including changes in the interpretation of existing requirements or programs to implement those requirements. We do not believe we would be affected by any such regulatory changes in a materially different way than our similarly situated competitors.
Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe the
regulation of similarly situated intrastate natural gas transportation in states in which we operate and ship natural gas on an intrastate basis will not affect our operations in a way that materially differs from the effect on the operations of our similarly situated competitors.
Regulation of
Productionproduction
The production of crude oil and natural gas is subject to regulation under a wide range of
local,federal, state and
federallocal statutes, rules, orders and
regulations. Federal, state and local statutes and regulations,
which require,
among other matters, permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation,
matters, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. The effect of these regulations is to limit the amount of crude oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production, severance or excise tax with respect to the production and sale of crude oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the crude oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Other
Federal Lawsfederal laws and
Regulations Affecting Our Industryregulations affecting our industry
Dodd-Frank Wall Street Reform and Consumer Protection Act. In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. This financial reform legislation includes provisions that require over-the-countermany derivative transactions that were then executed over-the-counter to be executed through an exchange orand be centrally cleared. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules and regulations to implement the new legislation. The CFTC has issued final regulations to implement significant aspects of the legislation, including new rules for the registration of swap dealers and major swap participants (and related definitions of those terms), definitions of the term “swap,” rules to establish the ability to rely on the commercial end-user exception from the central clearing and exchange trading requirements, requirements for reporting and recordkeeping,record keeping, rules on customer protection in the context of cleared swaps, and position limits for swaps and other transactions based on the price of certain reference contracts, some of which are referenced in our swap contracts. The position limits regulation has been vacated by a Federal court; however, the CFTC has proposed replacement rules. Key regulations that have not yet been finalized include those clarifying the definitions of “swap dealer,” “major swap participant” and “swap” and those establishing margin requirements for uncleared swaps and variousregulatory capital requirements for swap dealers.
In December 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants. Mandatory clearing is now required for all such market participants, unless an exception is available, and certain interest rate swaps became subject to the trade execution requirements on February 15, 2014. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps, and the trade documentation requirements. Theseexecution requirement does not apply to swaps that are not subject to a clearing mandate. Although we expect to qualify for the end-user exception from the clearing requirement for our swaps, mandatory clearing requirements and revised capital requirements applicable to other market participants, such as swap dealers, along with changes to the markets for swaps as a result of the trade execution requirement, may change the cost and availability of the swaps we use for hedging.
The CFTC’s swap regulations may require or cause our counterparties to collect margin from us, and if any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may require usbe required to clear oursuch transactions or execute them on a derivatives contract market or swap execution facility, although the application of those provisions to us is uncertain at this time.facility. The ultimate effect of the proposed new rules and any additional regulations on our business is uncertain. Of particular concern is whether the provisions of the final rules and regulations will allow us to qualifyour status as a non-financial, commercial end user that is exempt from the requirement to clear our derivative contracts, and whether our statusend-user will allow our derivative counterparties to not require us to post margin in connection with our commodity price risk management activities. The remaining final rules and regulations on major provisions of the legislation, such as new margin requirements, are towill be established through regulatory rulemaking. rule making.
In addition to the CFTC’s swap regulations, other jurisdictions, including Canada, the European Union, Switzerland, Hong Kong, Singapore, Japan and Australia, are in the process of adopting or implementing laws and regulations relating to transactions in derivatives, including margin and central clearing requirements, which in each case may affect our counterparties and the derivatives markets generally. Other rules, including the restrictions on proprietary trading adopted under Section 619 of the Dodd-Frank Act, also known as the Volcker Rule, may alter the business practices of our counterparties and in some cases may cause them to stop transacting in or making markets in derivatives. Moreover, federal banking regulators are reevaluating the authorization under which banking entities subject to their authority may engage in physical commodities transactions.
Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area, to the extent applicable to us or our derivative counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial and commercial risks related to fluctuations in commodity
prices,prices. Additional effects of the new regulations, including increased regulatory reporting and recordkeeping
costs, increased regulatory capital requirements for our counterparties, and market dislocations or disruptions, among other consequences,
and could have an adverse effect on our ability to hedge risks associated with our business.
Additionally, the SEC had planned to adopt the Dodd-Frank Act requirement that registrants disclose certain payments made to the U.S. Federal government and foreign governments in connection with the commercial development of crude oil, natural gas or minerals. The disclosure requirements were challenged by certain business groups and were subsequently vacated by a Federal court in July 2013. The SEC did not appeal the ruling and plans to issue a revised proposal, the timing of which is uncertain.
The SEC has adopted the Dodd-Frank Act requirement that registrants disclose the use of conflict minerals in their products, and whether any of those minerals originated in certain conflict-ridden regions of Africa and financed or benefited armed groups. Certain business groups challenged the disclosure requirements; however, the requirements were upheld by a Federal court in a July 2013 ruling. The ruling has been appealed by the plaintiffs involved in the matter. We monitor our operations to determine if any disclosure or reporting obligations arise under the conflict mineral rules.
Energy Policy Act of 2005. The Energy Policy Act of 2005 (“EPAct 2005”) included a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and made significantchanges to the statutory framework affecting the energy industry. Among other matters, EPAct 2005 amended the NGA to add an anti-market manipulation provision that makesmaking it unlawful for any entity, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. In January 2006, the FERC issued rules implementing the anti-market manipulation provision of EPAct 2005. These anti-market manipulation rules apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements as described further below.
The EPAct 2005 also provided the FERC with additional civil penalty authority. The EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1,000,000 per day
per violation for violations of the NGA and NGPA. Under EPAct 2005, the FERC also has authority to order disgorgement of profits associated with any violation. The anti-market manipulation rules and enhanced civil penalty authority reflect an expansion of the FERC’s enforcement authority.
FERC Market Transparency and Reporting Rules. The FERC requires wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers, and natural gas producers, to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. The FERC also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. Failure to comply with these reporting requirements could subject us to enhanced civil penalty liability provided under EPAct 2005.
FTC and CFTC Market Manipulation Rules. Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the FTC. Under the EISA, the FTC issued its Petroleum Market Manipulation Rule (the “Rule”), which became effective November 4, 2009, and prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. The Rule also bans intentional failures to state a material fact when the omission makes a statement misleading and distorts, or is likely to distort, market conditions for any product covered by the Rule. The FTC holds substantial enforcement authority under the EISA, including authority to request that a court impose fines of up to $1,000,000 per day per violation. Under the Commodity Exchange Act, the CFTC is directed to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act, the CFTC has adopted anti-market manipulation regulations that prohibit, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to assess fines of up to the greater of $1,000,000 or triple the monetary gain for violations of its anti-market manipulation regulations.regulations. Knowing or willful violations of the Commodity Exchange Act may also lead to a felony conviction. Additional proposals and proceedings that
mightmay affect the crude oil and natural gas industry are pending before the U.S. Congress, the FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our crude oil and natural gas operations. We do not believe we
wouldwill be affected by any such action materially different than similarly situated competitors.
Environmental, Healthhealth and Safety Regulationsafety regulation
GeneralGeneral. Our operations are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:
require the acquisition of various permits before drilling commences;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with crude oil and natural gas drilling, production and transportation activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals; and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
These laws and regulations may also restrict the rate of crude oil and natural gas production below a rate
that would otherwise
be possible. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business and affects profitability. Additionally, the U.S. Congress and federal and state agencies frequently revise environmental, health and safety laws,
rules and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the crude oil and natural gas industry could have a significant impact on our operating costs.
Environmental protection and natural gas flaring initiatives. Continental is committed to conducting its operations in a manner that protects the health, safety and welfare of the public, its employees and the environment. We strive to operate in accordance with all applicable regulatory requirements and have focused on continuously improving our health, safety, security and environmental (“HSS&E”) performance. We believe excellent HSS&E performance is critical to the long-term success of our business, and is a key component in maximizing return to shareholders. We also believe achieving this excellence requires the commitment and involvement of all employees in the Company, and we expect the same level of commitment from our contractors and vendors. Our commitment to HSS&E excellence is a paramount objective.
In connection with our HSS&E initiatives, we actively work to identify and manage the environmental risks and impact of our operations. Further, we set corporate objectives aimed at producing continuous improvement of our HSS&E efforts and we seek to provide the leadership and resources to enable our workforce to achieve our objectives. We routinely monitor our HSS&E performance to assess our conformity with environmental protection initiatives.
We take a proactive and disciplined approach to emergency preparedness and business continuity planning to address the health, safety, security, and environmental risks inherent to our industry. We continually train our workforce and conduct drills to improve awareness and readiness to mitigate such risks. Further, emergency response plans are maintained that establish procedures to be utilized during any type of emergency affecting our personnel, facilities or the environment.
One current focus of our HSS&E initiatives is the reduction of air emissions produced from our operations, particularly with respect to flaring of natural gas from our operated well sites in the Bakken field of North Dakota, our most active area. The rapid growth of crude oil production in North Dakota in recent years, coupled with a lack of established natural gas
transportation infrastructure in the state, has led to an industry-wide increase in flaring of natural gas produced in association with crude oil production. We recognize the environmental and financial risks associated with natural gas flaring and manage these risks on an ongoing basis. We set internal flaring reduction targets and to date have taken numerous actions to reduce flaring from our operated well sites. Our ultimate goal is to reduce natural gas flaring from our operated well sites to as close to zero percent flaring as possible. In operating areas such as the Buffalo Red River units in South Dakota, the quality of the natural gas is not adequate to meet requirements for sale, so we employ processes to efficiently combust the gas and minimize impacts to the environment.
In 2013, we continued to make notable progress in adhering to our flaring reduction initiatives. The percentage of our operated natural gas production flared in North Dakota Bakken, our most active area, was less than 11% in 2013, compared to 15% in 2012 and 19% in 2011. We believe this reduction is a notable accomplishment given the significant increase in our natural gas production in the Bakken field, including areas with less developed infrastructure. Flaring from our operated well sites in North Dakota Bakken is significantly less than our industry peers operating in the play. According to data published by the North Dakota Industrial Commission ("NDIC"), our industry as a whole was flaring approximately 30% of produced natural gas volumes in the state as of late 2013. Since we are one of the largest producers in the North Dakota Bakken field, we believe the percentage of natural gas flared by the industry as a whole would be higher than 30% if Continental’s results were excluded from the NDIC’s data. Continental is a participant in the NDIC’s Flaring Reduction Task Force and is actively engaged in working with other task force members and the NDIC to develop action plans for mitigating natural gas flaring in the state.
We are experiencing similar or better flaring results in our other key operating areas outside of North Dakota. In Montana Bakken, we flared approximately 9% of the natural gas produced from our operated well sites in 2013. Additionally, flared natural gas volumes from our operated SCOOP and Northwest Cana properties in Oklahoma are negligible given the existence of established natural gas transportation infrastructure in that state.
Through our HSS&E initiatives, we will continue to work toward maintaining an industry-leading position with respect to flaring reduction efforts in North Dakota and our other key operating areas. We expect to further reduce flared natural gas volumes as we continue to build out transportation infrastructure and transition to a greater use of pad drilling in 2014 and beyond. Our flaring reduction progress is and will be dependent upon external factors such as investment from third parties in the development of gas gathering systems, state regulations, and the granting of reasonable right-of-way access by land owners, among other factors.
We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Although we believe our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not materially impact our financial position or results of operations.
Environmental, health and safety laws and regulations. Some of the existing environmental, health and safety laws and regulations to which we are subject to include, among others: (i) regulations by the Environmental Protection Agency (“EPA”) and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act and analogous state laws that may require the removal of previously disposed wastes (including wastes disposed of or released by prior owners or operators), the cleanup of property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) federal pipelineDepartment of Transportation safety laws and comparable state and local requirements; (iv) the Clean Air Act and comparable state and local requirements, which establish pollution control requirements with respect to air emissions from our operations; (v) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (vi) the Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws which impose restrictions and strict controls with respect to the discharge of pollutants, including crude oil and other substances generated by our operations, into waters of the United States or state waters; (vii) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of solid and hazardous wastes, and comparable state statutes; (viii) the Safe Drinking Water Act and analogous state laws which impose requirements relating to our underground injection activities; (ix) the National Environmental Policy Act and comparable state statutes, which require government agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment; (x) the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes, which require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations, and (xi) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material.We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Although we believe our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operations.
Climate change. Federal, state and local laws and regulations are increasingly being enacted to address concerns about the effects the emission of carbon dioxide and other identified “greenhouse gases” may have on the environment and climate
worldwide. These effects are widely referred to as “climate change.” Since its December 2009 endangerment finding regarding the emission of carbon dioxide, methane and other greenhouse gases, the EPA has begun regulating sources of greenhouse gas emissions under the federal Clean Air Act. Among several regulations requiring reporting or permitting for greenhouse gas sources, the EPA finalized its “tailoring rule” in May 2010 that
determinesidentifies which stationary sources of greenhouse gases are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology for, their greenhouse gases. In November 2010, the EPA also finalized its greenhouse gas reporting requirements
beginning in March 2012, for certain oil and gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year.
The rule requires annual reporting to the EPA of greenhouse gas emissions by such regulated facilities.
In April 2012, the EPA issued final rules that established new air emission controls for crude oil and natural gas production and natural gas processing operations. These rules were published in the Federal Register on August 16, 2012. The EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with crude oil and natural gas production and processing activities. The final rules require the use of reduced emission completions or “green completions” on all hydraulically-fractured wells completed or refractured after January 1, 2015 in order to achieve a 95% reduction in the emission of VOCs. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules may require modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Moreover, in recent
pastyears the U.S. Congress has considered establishing a cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. Under past proposals, the EPA would issue or sell a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of such legislation, if
ever adopted, would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products, and natural gas. In addition, while the prospect for such cap-and-trade legislation by the U.S. Congress remains uncertain, several states
including states in which we operate, have adopted, or are in the process of adopting, similar cap-and-trade programs.
As a crude oil and natural gas company, the debate on climate change is relevant to our operations because the equipment we use to explore for, develop and produce crude oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the crude oil and natural gas we sell, emits carbon dioxide and other greenhouse gases. Thus, any current or future federal, state or local climate change initiatives could adversely affect demand for the crude oil and natural gas we produce by stimulating demand for alternative forms of energy that do not rely on the combustion of fossil fuels, and therefore could have a material adverse effect on our business. Although our compliance with any greenhouse gas regulations may result in increased compliance and operating costs, we do not expect the compliance costs for currently applicable regulations to be material. Moreover, while it is not possible at this time to estimate the compliance costs or operational impacts for any new legislative or regulatory developments in this area, we do not anticipate being impacted to any greater degree than other similarly situated competitors.
Hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formations to stimulate crude oil and natural gas production. Some activists have attempted to link hydraulic fracturing to various environmental problems, including adverse effects to drinking water supplies and migration of methane and other hydrocarbons. As a result, several federal agencies are studying the environmental risks with respect to hydraulic fracturing or evaluating whether to restrict its use. From time to time, legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities from the definition of “underground injection,” thereby requiring the crude oil and natural gas industry to obtain permits for hydraulic fracturing and to require disclosure of the additives used in the process. If ever adopted, such legislation could establish an additional level of regulation and permitting at the federal level.
Scrutiny of hydraulic fracturing activities continues in other ways,ways. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing environmental issues associated with thehydraulic fracturing. The EPA havinghas commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the initialdraft results of which are anticipated to be available by late 2012. The U.S. Departmentin 2014. Further, on May 11, 2012, the Bureau of the Interior has announced it will publish rules requiring companies to disclose the make-upLand Management (“BLM”) issued a proposed rule that would require public disclosure of all materialschemicals used in hydraulic fracturing fluids on federal lands. The announced legislation will also require disclosure of the source, access routeoperations, and transport ofimpose other operational requirements for all water anticipated to be used in connection with hydraulic fracturing operations. The announced rules have not been published and we are not able to determine the extent of their impact on our operations on federal land.lands, including Native American trust lands. BLM published a supplemental notice of proposed rulemaking on May 24, 2013, which replaced the proposed rulemaking issued by the agency in May 2012. Additionally, on February 11, 2014 the EPA issued guidance governing the use of diesel fuel in hydraulic fracturing fluids. The guidance
identifies five different variations of diesel and outlines new permitting guidelines for their use, along with technical recommendations for meeting the standards. In addition to these federal initiatives, several state and local governments, including states in which we operate, have moved to require disclosure of fracturing fluid components or otherwise to regulate their use more closely. In certain areas of the United States, new drilling permits for hydraulic fracturinghave been put on hold pending development of additional standards. We voluntarily participate in FracFocus, a national publicly accessible Internet-based registry developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. This registry, located at www.fracfocus.org, provides our industry with an avenue to voluntarily disclose additives used in the hydraulic fracturing process. We currently disclose the additives used in the hydraulic fracturing process on all wells we operate.
The adoption of any future federal, state or local laws,
rules or implementing regulations imposing permitting or reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult and more expensive to complete crude oil and natural gas wells in low-permeability formations, increase our costs of compliance and doing business, and delay, prevent or prohibit the development of natural resources from unconventional formations. Compliance, or the consequences of
anyour failure to comply,
by us, could have a material adverse effect on our financial condition and results of operations. At this time it is not possible to estimate the potential impact on our business if
thissuch federal or state legislation is enacted into law.
As of December 31,
2011,2013, we employed
609 people, including 343 employees in drilling and production.929 people. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced
any strikes or work stoppages. We consider our relations with our employees to be satisfactory. We utilize the services of independent contractors to perform various field and other services.
Company Contact Information
Our corporate internet website iswww.contres.com.www.clr.com. Through the investor relations section of our website, we make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after the report is filed with or furnished to the SEC. For a current version of various corporate governance documents, including our Code of Ethics, please see our website. We intend to disclose amendments to, or waivers from, our Code of Ethics by posting to our website. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report. We intend to use our website as a means of disclosing material information and for complying with our disclosure obligations under SEC Regulation FD. Such disclosures will be included on our website in the “For Investors” section. Accordingly, investors should monitor that portion of our website in addition to following our press releases, SEC filings and public conference calls and webcasts.
We file periodic reports and proxy statements with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website iswww.sec.gov. Our principal executive offices are located at
30220 N.
Independence, Enid,Broadway, Oklahoma
73701,City, Oklahoma 73102, and our telephone number at that address is
(580) 233-8955.(405) 234-9000.You should carefully consider each of the risks described below, together with all other information contained in this report, before deciding to invest in shares of our common stock. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline and you may lose all or part of your investment.
We are subject to certain risks and hazards due to the nature of
ourthe business
activities.activities we conduct. The risks discussed below, any of which could materially and adversely affect our business, financial condition, cash flows, and results of operations, are not the only risks we face. We may experience additional risks and uncertainties not
currently known to us or, as a result of developments occurring in the future. Further,future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations in the future.
operations.
A substantial or extended decline in crude oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure needs and financial commitments.
The price we receive for our crude oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
worldwide and regional economic conditions impacting the global supply and demand for crude oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries;
the price and quantity of imports of foreign crude oil and natural gas;
political conditions in or affecting other crude oil-producing and natural gas-producing countries;
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulations;
the level of national and global crude oil and natural gas exploration and production;
the level of national and global crude oil and natural gas inventories;
localized supply and demand fundamentalsfundamentals;
the availability, proximity and capacity of transportation, availability;processing, storage and refining facilities;
changes in supply, demand, and refinery capacity for various grades of crude oil and natural gas;
the ability of refineries in the United States to accommodate increasing domestic supplies of light sweet crude oil;
the level and effect of trading in commodity futures markets;
weather conditions;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
fuels or other energy sources.Lower crude oil and natural gas prices could reduce our cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes;
result in a decrease in the borrowing base under our revolving credit facility or otherwise limit our ability to borrow money or raise additional capital; and reduce the amount of crude oil and natural gas we can economically produce.
Substantial, extended decreases in crude oil and natural gas prices would render uneconomic a significant portion of our exploration, development and exploitation projects. This may result in significant downward adjustments to our estimated proved reserves. As a result, a substantial
or extended decline in crude oil or natural gas prices would materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
A substantial portion of our producing properties are located in the North region, making us vulnerable to risks associated with having operations concentrated in this geographic area.
Because our
Our operations are geographically concentrated in the North region, (76%with that region comprising approximately 77% of our crude oil and natural gas production and approximately 86% of our crude oil and natural gas revenues for the year ended December 31, 2013. Additionally, as of December 31, 2013 approximately 76% of our estimated proved reserves were located in the fourth quarterNorth region.
Because of
2011 was from the North region),this geographic concentration, the success and profitability of our operations may be
disproportionallydisproportionately exposed to the effect of regional events. These include, among others, fluctuations in the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and
otherrail transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor and infrastructure capacity. In addition, our operations in the North region may be adversely affected by seasonal weather and lease stipulations designed to protect wildlife, which can intensify
competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in the North region also increases exposure to unexpected events that may occur in this region such as natural disasters, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, and results of operations.
operations and cash flows.
Volatility in the financial markets or in global economic factors could adversely impact our business and financial condition.
In recent years, U.S.
United States and global economies
and financial systems have experiencedmay experience periods of turmoil and
upheavalvolatility from time to time, which may be characterized by
extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets,
the bankruptcy, failure, collapse or sale of financial institutions, increased levels ofhigh unemployment,
unstable consumer confidence and
an unprecedented level of intervention by the U.S. federal government and other governments. Although some portions of the economy appear to have stabilized, and there have been signs of the beginning of recovery, the extent and timing of a recovery, and whether it can be sustained are uncertain. Continued economic weaknessdiminished consumer spending. Economic turmoil or uncertainty could reduce demand for crude oil and natural gas and put downward pressure on the prices of crude oil and natural gas. This would negatively impact our revenues, margins, profitability, operating cash flows, liquidity and financial condition. Such weakness or uncertainty could also cause our commodity hedging arrangements to become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. Furthermore, our ability to collect receivables may be adversely impacted.
Historically, we have used cash flows from operations, borrowings under our
revolving credit facility and capital market transactions to fund capital expenditures. Volatility in U.S. and global financial and equity markets, including market disruptions, limited liquidity, and interest rate volatility, may increase our cost of financing. We have
an existing revolvinga credit facility with lender commitments totaling
$1.25 billion and a borrowing base of $2.25 billion as of February 15, 2012.$1.5 billion. In the future, we may not be able to access adequate funding under our
bank credit facility as a result of (i) a decrease in our
credit ratings that triggers the reinstatement of a borrowing base
duerequirement, subjecting us to the
outcomerisk that other events may adversely impact the size of
a subsequentour borrowing base
redetermination, which is solely at the discretion of our lenders,following reinstatement, (ii) a decline in commodity prices, or
(ii)(iii) an unwillingness or inability on the part of our lending counterparties to meet their funding
obligations. Declines in commodity prices could result in a determination to lower our borrowing base inobligations or increase their commitments as required under the
future and, in such case, we could be required to repay indebtedness in excess of the borrowing base.credit facility. Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required and on terms we find acceptable. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due.
Should any one of the above risks occur, itthey could have a material adverse effect on our financial condition and results of operations.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on
satisfactoryacceptable terms, which could lead to a decline in our crude oil and natural gas reserves and production.
The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. In
2011,2013, we invested
$2.2approximately $3.84 billion in our capital
program.program, inclusive of property acquisitions. In October 2012, we announced a five-year growth plan to triple our production and proved reserves from year-end 2012 to year-end 2017. Our capital expenditures for
20122014 are budgeted to be
$1.75$4.05 billion,
excluding acquisitions which are not budgeted, with
$1.63$3.69 billion allocated for drilling, capital workovers and facilities. To date,
theseour capital expenditures have been financed with cash generated by operations, borrowings under our
revolving credit facility and the issuance of debt and equity securities. The actual amount and timing of future capital expenditures may differ materially from our estimates as a result of, among
other things,others, commodity prices,
available cash flows, unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment,
the availability of transportation capacity, and regulatory, technological and competitive developments. Continued improvementImprovement in commodity prices may result in an increase in actual capital expenditures. Conversely, a significant decline in commodity prices could result in a decrease in actual capital expenditures. We intend to finance future capital expenditures primarily through cash flows from operations and borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional debt requires a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital needs, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
Our cash flows from operations and access to capital are subject to a number of variables,
including:including but not limited to:the amount of our proved reserves;
the volume of crude oil and natural gas we are able to produce and sell from existing wells;
the prices at which crude oil and natural gas are sold;
our ability to acquire, locate and produce new reserves; and
the ability and willingness of our banks to extend credit.
credit or the financial markets to accept offerings of our senior notes.If revenues or the borrowing base under our revolving credit facilityability to borrow decrease as a result of lower crude oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by
operations or cash available under our
revolving credit facility is not sufficient to meet capital requirements, the failure to obtain additional financing could result in a curtailment of operations relating to development of our prospects, which in turn could lead to a decline in our crude oil and natural gas reserves and could adversely affect our business, financial condition and results of
operations.operations and our ability to achieve our growth plan.
Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.
Risks we face while drilling include, but are not limited to, failing to place our well bore in the desired target producing zone; not staying in the desired drilling zone while drilling horizontally through the formation; failing to run our casing the entire length of the well bore; and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages; failing to run tools the entire length of the well bore during completion operations; and not successfully cleaning out the well bore after completion of the final fracture stimulation stage.
Further, many factors may curtail, delay or cancel scheduled drilling projects,
including;including:abnormal pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment andor qualified personnel;
shortages of or delays in obtaining components used in hydraulic fracturing processes such as water and proppants;
mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines equipment failures or accidents;train derailments;
adverse weather conditions and natural disasters, such as flooding, blizzards and ice storms;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
reductions in crude oil and natural gas prices;
limited availability of financing with acceptable terms;
environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by third party service providers;
providers or us;limitations in infrastructure, including transportation capacity, or in the market for crude oil and natural gas; and
delays imposed by or resulting from compliance with regulatory requirements.
requirements including permitting.Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The Company's current estimates of reserves could change, potentially in material amounts, in the future.
The process of estimating crude oil and natural gas reserves is complex.complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves. SeePart I, Item 1. Business—Crude Oil and Natural Gas Operations, Proved Reserves for information about our estimated crude oil and natural gas reserves, PV-10, and Standardized Measure of discounted future net cash flows as of December 31, 2011.2013. In order to prepare reserves estimates, we must project production rates and the amount and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and
reliability of this data can
vary.vary with the uncertainty of decline curves and the ability to model heterogeneity of the porosity, permeability and pressure relationships in unconventional resources. The process also requires economic assumptions, based on historical data but projected into the future, about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves will vary
and could vary significantly from our estimates. Any significant variance could materially affect the estimated quantities and present value of our
reserves.reserves, which in turn could have an adverse effect on the value of our assets. In addition, we may adjust estimates of proved reserves,
potentially in material amounts, to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves.
You should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC rules, we base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future
prices may be materially higher or lower than the SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:
actual prices we receive for crude oil and natural gas;
the actual cost and timing of development and production expenditures;
the amount and timing of actual production;
the actual prices we receive for sales of crude oil and natural gas; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry in general.
Actual future prices and costs may materially differ from those used in
our estimate of the present value
estimate.of future net revenues. If crude oil prices decline by $10.00 per barrel, our PV-10 as of December 31,
20112013 would decrease approximately
$1.3$2.8 billion. If natural gas prices decline by $1.00 per Mcf, our PV-10 as of December 31,
20112013 would decrease approximately
$594 million.$1.3 billion.
Our use of enhanced recovery methods creates uncertainties that could adversely affect our results of operations and financial condition.
One of our business strategies is to
commerciallyeconomically develop unconventional crude oil and natural gas resource plays using enhanced recovery technologies. For example, we
may inject water and high-pressure air into formations on some of our properties to increase the production of crude oil and natural gas. The additional production and reserves attributable to the use of these enhanced recovery methods are inherently difficult to predict. If enhanced recovery programs do not allow for the extraction of crude oil and natural gas in the manner or to the extent we anticipate, our future results of operations and financial condition could be materially adversely affected.
If crude oil and natural gas prices decrease, we may be required to
take write-downs ofwrite down the carrying values of our crude oil and natural gas properties.
Accounting rules require that we periodically review the carrying values of our crude oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying values of our crude oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our cash flows and results of operations.
Unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services,
including key components used in hydraulic fracturing processes such as water and proppants, could delay or cause us to incur significant expenditures not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
We may incur substantial losses and be subject to substantial liability claims as a result of our crude oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and
underinsuredunder insured events could materially and adversely affect our business, financial condition or results of operations. Our crude oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:
environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
fires, explosions and ruptures of pipelines;
loss of product or property damage occurring as a result of transfer to a rail car or train derailments;
personal injuries and death;
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by third party service providers.
providers or us.Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
damage to andor destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
We may elect not to obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event
that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Prospects we decide to drill may not yield crude oil or natural gas in economically producible quantities.
Prospects we decide to drill that do not yield crude oil or natural gas in economically producible quantities may adversely affect our results of operations and financial condition. In this report, we describe some of our current prospects and plans to explore
those prospects. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. It is not possible to predict with certainty in advance of drilling and testing whether any particular prospect will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or be economically producible. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in economically producible quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals,
available transportation capacity, and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire.
UnlessIf we are
not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents
72%60% of our total net undeveloped acreage at December 31,
2011.2013. At that date, we had leases representing
219,845249,525 net acres expiring in
2012, 418,5042014, 368,700 net acres expiring in
2013,2015, and
245,396296,360 net acres expiring in
2014. As such, our2016. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Our business depends on crude oil and natural gas transportation facilities, most of which are owned by third parties, and on the availability of rail
transportation.transportation
The marketability of our crude oil and natural gas production depends in part on the availability, proximity and capacity of pipeline and rail systems owned by third parties. The lack or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of crude oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and rail systems, labor disputes
in the rail industry and general economic conditions could adversely affect our ability to produce, gather,
transport and
transportsell crude oil and natural gas.
AsWe presently transport a
resultsignificant portion of
pipeline constraints and the continuous increase in Williston Basin production, in December 2011 we transported approximately 30% of theoperated crude oil production from our North
Regionregion to market centers by
rail.rail, with approximately 70% of such production being shipped by rail in December 2013.
The disruption of third-party pipelines or rail transportation facilities due to labor disputes, maintenance, and/civil disturbances, public protests, terrorist attacks, cyber attacks, adverse weather, regulatory developments, equipment failures or weatheraccidents, including pipeline ruptures or train derailments, could negatively impact our ability to market and deliver our products.products and achieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such pipeline or rail facilities willwould be restored or what prices willwould be charged. A significant shut-in of production in connection with any of the aforementioned items could materially affect our cash flows, and if a substantial portion of the impacted production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows. See the subsequent risk factor titled
Proposed legislation and regulation under consideration could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business for a discussion of regulations being introduced that could potentially impact the transportation of crude oil by rail. Our business depends on the availability of water. Limitations or restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
With current technology, water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal could limit our ability to use techniques such as hydraulic fracturing. This could have a material adverse effect on our ability to economically find and develop crude oil and natural gas reserves.
We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in developed and producing areas. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our crude oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations.regulations, including those governing environmental protection, health and safety, and the discharge of materials into the environment. In order to conduct operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. WeEnvironmental regulations may incurrestrict the types, quantities and concentration of materials that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial costs in order to maintain compliance with these existing laws and regulations. In addition,liabilities for pollution resulting from our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, crude oil and natural gas.
Failure to comply with
suchthese laws and regulations
as interpretedmay trigger a variety of administrative, civil and
enforced, could have a material adverse effect on our business, financial conditioncriminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and
resultsthe issuance of
orders enjoining future operations.
SeePart I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a description of the laws and regulations that affect us.Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions. In addition,For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for damages to personspersonal injury and property damage and fines or property, including natural resources, may result frompenalties for related violations of environmental laws or regulations.
Moreover, our operations.Newcosts of compliance with existing laws regulations or enforcement policies could be more stringentsubstantial and imposemay increase or unforeseen liabilities could be imposed if existing laws and regulations are revised or significantly increase compliance costs.reinterpreted, or if new laws and regulations become applicable to our operations. If we are not able to recover the resultingincreased costs through insurance or increased revenues, our business, financial condition and results of operations could be adversely affected.
See
Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a description of the laws and regulations that affect us. Climate change legislation or regulations governing the emissions of “greenhouse gases” could result in increased operating costs and reduce demand for the crude oil, natural gas and natural gas liquids we produce.
On
In December
15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climate changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of several regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act, such as the so-called “tailoring rule” adopted in May 2010, which imposes permitting and best available control technology requirements on the largest greenhouse gas stationary sources. In November 2010, the EPA also finalized its greenhouse gas reporting requirements
beginning in March 2012, for certain oil and gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year.
We currently estimate our producing wells in five basins will be subjectThe rule requires annual reporting to the
reporting requirements.EPA of greenhouse gas emissions by such regulated facilities.
In April 2012, the EPA issued final rules that established new air emission controls for crude oil and natural gas production and natural gas processing operations. These rules were published in the Federal Register in August 2012. The EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with crude oil and natural gas production and processing activities. The final rules require the use of reduced emission completions or “green completions” on all hydraulically-fractured wells completed or refractured after January 1, 2015 in order to achieve a 95% reduction in the emission of VOCs. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules may require modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, and almost half of the states, including states in which we operate, have enacted or passed measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional
greenhouse gas cap-and-trade programs. Most of these cap-and-trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. These reductions may cause the cost of allowances to escalate significantly over time.
The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and
report on greenhouse gas emissions or reduce emissions of greenhouse gasgases associated with our operations. In addition, these regulatory initiatives could drive down demand for our products by stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition and results of operations.
Finally, it should be noted some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur
as a result of climate change or otherwise, they could have an adverse effect on our assets and operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and inability to book future reserves.
A significant majority of our operations utilize hydraulic fracturing, an important and commonly used process in the completion of crude oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the high-pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Some activists have attempted to link hydraulic fracturing to various environmental problems, including adverse effects to drinking water supplies as well as migration of methane and other hydrocarbons. As a result, several federal agencies are studying potential environmental risks with respect to hydraulic fracturing or evaluating whether to restrict its use. From time to time legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities from the definition of “underground injection,” thereby requiring the crude oil and natural gas industry to obtain permits for hydraulic fracturing, and to require disclosure of the additives used in the process. If ever adopted, such legislation could establish an additional level of regulation and permitting at the federal level.
Scrutiny of hydraulic fracturing activities continues in other
ways,ways. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing environmental issues associated with
thehydraulic fracturing. The EPA
commencinghas commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the
initialdraft results of which are anticipated to be available
by late 2012. The U.S. Departmentin 2014. Further, in May 2012, the BLM issued a proposed rule that would require public disclosure of
the Interior has announced it will publish rules requiring companies to disclose the make-up of all materialschemicals used in hydraulic fracturing
fluids on federal lands. The announced legislation will also require disclosure of the source, access routeoperations, and
transport ofimpose other operational requirements for all
water anticipated to be used in connection with hydraulic fracturing
operations. The announced rules have not been published and we are not able to determine the extent of their impact on our operations on federal
land. Atlands, including Native American trust lands. BLM published a supplemental notice of proposed rulemaking on May 24, 2013, which replaced the proposed rulemaking issued by the agency in May 2012. Additionally, on February 11, 2014 the EPA issued guidance governing the use of diesel fuel in hydraulic fracturing fluids. The guidance identifies five different variations of diesel and outlines new permitting guidelines for their use, along with technical recommendations for meeting the standards. As of December 31,
2011,2013, we held approximately
75,200183,200 net undeveloped acres on federal land, representing approximately
6%12% of our total net undeveloped acres. In addition to these federal initiatives, several state and local governments, including states in which we operate, have moved to require disclosure of fracturing fluid components or to otherwise regulate their use more closely. In certain areas of the United States, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards.
The adoption of any future federal, state or local law or implementing regulation imposing permitting or reporting obligations on, or otherwise limiting, the hydraulic fracturing process, or the discovery of groundwater contamination or other adverse environmental effects directly connected to hydraulic fracturing, could make it more difficult and more expensive to complete crude oil and natural gas wells in low-permeability formations and increase our costs of compliance and doing business, as well as delay, prevent or prohibit the development of natural resources from unconventional formations. In the event regulations are adopted that prohibit or significantly limit the use of hydraulic fracturing in states in which we operate, it would have a material adverse effect on our ability to economically find and develop crude oil and natural gas reserves in our strategic plays. The inability to achieve a satisfactory economic return could cause us to curtail or discontinue our exploration and development plans. Such a circumstance would have a material adverse effect on our business and would impair our ability to implement our growth plan.
Should we fail to comply with
all applicable FERC,
FTC and CFTC administered statutes
rules,and regulations
and orders,on market behavior, we could be subject to substantial penalties and
fines.fines and other liabilities.
The FERC, under the EPAct 2005, and the FTC, under the
Energy Independence and Security Act of 2007, may impose or seek to impose through judicial action penalties for violations of anti-market manipulation rules for natural gas, crude oil and petroleum products of up to $1,000,000 per day for each violation. The CFTC, under the Commodity Exchange Act, has similar authority to
imposeassess penalties of up to
the greater of $1,000,000
or triple the monetary gain for violation of anti-market manipulation rules for certain derivative contracts.
Knowing or willful violations of the Commodity Exchange Act may also lead to a felony conviction. In addition, while we have not been regulated by the FERC as a natural gas company under the NGA, the FERC has adopted regulations that may subject us to the FERC annual reporting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC,
the FTC or CFTC from time to time. Failure to comply with any of these regulations in the future could subject us to civil penalty liability, as well as the disgorgement of profits and third-party claims.
Proposed legislation
and regulation under consideration could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.
Our operations are subject to extensive federal, state and local laws and regulations.
Changes to existing laws or regulations,
or new laws or
regulations, or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products.
ThisSimilarly, changes in regulatory policies and priorities could result in the imposition of new obligations upon us, such as increased reporting or audits. Any of these requirements could result in increased operating costs and
could have a material adverse effect on our financial condition and results of operations.
The U.S. Congress and various states are considering other legislation that, if adopted in its current proposed form, would subject companies involved in crude oil and natural gas exploration and production activities to substantial additional regulation. If such legislation,
isregulation or other requirements are adopted,
itthey could result in, among other items, additional
regulation oflimitations and restrictions on hydraulic fracturing of wells,
changes to the calculation of royalty payments, new safety requirements such as those involving rail transportation described below, and additional regulation of private energy commodity derivative and hedging activities. These and other potential laws,
regulations and
regulationsother requirements could increase our operating costs, reduce liquidity, delay operations or otherwise alter the way we conduct our business. This, in turn, could
in turn have a material adverse effect on our financial condition and results of operations.
We presently transport a significant portion of operated crude oil production from our North region to market centers by rail, with approximately 70% of such production being shipped by rail in December 2013. In response to recent train derailments occurring in the United States and Canada in 2013, U.S. regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the NTSB issued a series of recommendations to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) to develop an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity of product carried on a train, and (iii) to audit shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the U.S. Department of Transportation issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of petroleum crude oil be handled as a Packing Group I or II hazardous material. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications or construction of rail cars used to transport crude oil could result in severe transportation capacity constraints during the period in which new rail cars are retrofitted or constructed to meet new specifications.
We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.
Certain federal income tax deductions currently available with respect to
crude oil and
natural gas exploration and development may be eliminated as a result of future legislation.
Among the changes contained in President Obama’s fiscal year
20132014 budget proposal
released by the White House in February 2012, are the elimination or deferral of certain key U.S. federal income tax deductions currently available to crude oil and natural gas exploration and production companies. Such proposed changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for crude oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. These proposed changes, if enacted, may negatively affect our financial condition and results of operations. The passage of legislation
as a result of the proposed American Jobs Actin response to President Obama’s 2014 budget proposal or any other similar change in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to crude oil and natural gas exploration and development, and any such change could negatively affect our cash flows available for capital expenditures and our ability to achieve our growth plan.
Regulations under the Dodd-Frank Act regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risk and other risks associated with our business.
We use derivative instruments to manage
our commodity price risk. In 2010, the U.S. Congress adopted the Dodd-Frank
Wall Street Reform and Consumer Protection Act,
(HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.
The newThis financial reform legislation
was signed into law by President Obama on July 21, 2010includes provisions that require many derivative transactions that were then executed over-the-counter to be executed through an exchange and
requires the CFTC, theSEC, and in some cases banking regulators, to promulgate rules and regulations implementing the new legislation. The CFTC has issued final regulations to implement significant aspects of thebe centrally cleared. In addition, this legislation including new rulescalls for the registrationimposition of swap dealers and major swap participants, requirements for reporting and recordkeeping, rules on customer protection in the context of cleared swaps, and position limits for swaps, including swaps involving physical commodities such as crude oil and other transactions based onnatural gas, which have been proposed but have not been finalized. It also calls for the priceestablishment of certain reference contracts, some of which are referenced in our swap contracts. Key regulations not yet finalized include those clarifying the definitions of “swap dealer,” “major swap participant” and “swap” and those establishing margin requirements for uncleared swaps, which have not been finalized. If we do not qualify for the end user exception from any clearing requirements applicable to our swaps, the mandatory clearing requirements and various trade executionrevised capital requirements applicable to other market participants, such as swap dealers, may change the cost and trade documentation requirements as well as certain end-user exemptions. These regulations may require or cause our counterparties to collect margin from us and may require us to clear our transactions or execute them on a derivatives contract market or swap execution facility, although the application of those provisions to us is uncertain at this time. Someavailability of the swaps we use for managing commodity price risk. Some counterparties to our derivative instruments may also need or choose to spin off some of their derivativesderivative activities to a separate entity, which may not be as creditworthycredit worthy as our current counterparty.
The new legislation and
If we do not qualify for the end user exemption from any
applicable clearing requirements, the new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, lead to fewer potential counterparties, impose new recordkeeping and documentation requirements, and increase our exposure to less creditworthy counterparties.
The proposed position limits may limit our ability to implement price risk management strategies if we are not able to qualify for any exemption from such limits. Additionally, the margin requirements for uncleared swaps when enacted may require us to post collateral, which could adversely affect our available liquidity. If we reduce our use of derivatives as a result of the
legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position and results of operations.
Competition in the crude oil and natural gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing crude oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Certain of our competitors may possess and employ financial, technical and personnel resources greater than ours.
Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our financial condition and results of operations.
The loss of senior management or technical personnel could adversely affect our operations.
We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As of December 31,
2011,2013, non-operated properties represented
15%19% of our estimated proved developed reserves,
14%10% of our estimated proved undeveloped reserves, and
14%13% of our estimated total proved reserves. We have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures required to fund such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially adversely affect our financial condition and results of operations.
Our
revolving credit facility and the indentures for our senior notes contain certain covenants and restrictions that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.
Our
revolving credit facility and
thecertain indentures for our senior notes include
certain covenants and restrictions that
may, among
other things,others, restrict:
our investments, loans and advances and the paying of dividends and other restricted payments;
our incurrence of additional indebtedness;
the granting of liens, other than liens created pursuant to the revolving credit facility and certain permitted liens;
mergers, consolidations and sales of all or a substantial part of our business or properties;
the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities; and
The
Certain indentures for our outstanding senior notes
may limit our ability and the ability of our restricted subsidiaries to:
incur, assume or guarantee additional indebtedness or issue redeemable stock;
pay dividends on stock, repurchase stock or redeem subordinated debt;
make certain investments;
enter into certain transactions with affiliates;
create certain liens on our assets;
sell or otherwise dispose of certain assets, including capital stock of subsidiaries;
restrict dividends, loans or other asset transfers from our restricted subsidiaries;
enter into new lines of business; and
consolidate with or merge with or into, or sell all or substantially all of our properties to another person.
Our
revolving credit facility also requires us to maintain certain financial ratios, such as leverage ratios.
The restrictive covenants in our
revolving credit facility and the senior note indentures may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our
revolving credit facility or senior note indentures may be impacted by changes in economic or business conditions, results
of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, such lenders or trustees could elect to declare all amounts outstanding thereunder, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest under our revolving credit facility, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to beis accelerated, our assets may not be sufficient to repay in full such indebtedness.
indebtedness, which would adversely affect our financial condition and results of operations.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit ratings. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. For example, as of February
15, 2012,17, 2014, outstanding borrowings under our
revolving credit facility were
$900.0$560 million and the impact of a 1% increase in interest rates on this amount of debt would result in increased annual interest expense of approximately
$9.0$5.6 million and a
$5.6$3.5 million decrease in our annual net income. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
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 ($378.8656.2 million in receivables at December 31, 2011)2013), our joint interest receivables ($398.8350.0 million at December 31, 2011)2013), and counterparty credit risk associated with our derivative instrument receivables ($10.33.6 million at December 31, 2011)2013). Joint interest receivables arise from billing entities who 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. We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with several significant customers. The
three largest
purchaserpurchasers of our crude oil and natural gas during the year ended December 31,
20112013 accounted for
41%a combined 38% of our total
revenues.crude oil and natural gas revenues for the year. We generally do not require our
customerscounterparties to
post collateral.provide collateral to support crude oil and natural gas sales receivables owed to us. Additionally, our use of derivative instruments involves the risk that our counterparties will be unable to meet their obligations under the arrangements. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition and results of operations.
Our derivative activities could result in financial losses or reduce our earnings.
To achieve a more predictable cash flowflows and reduce our exposure to adverse fluctuations in the prices of crude oil and natural gas, we enter into derivative instruments for a portion of our crude oil and/or natural gas production, including collars and fixed price swaps. SeePart II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operations—Crude Oil and Natural Gas Hedging andPart II, Item 8. Notes to Consolidated Financial Statements – Statements—Note 5. Derivative Instrumentsfor a summary of our crude oil and natural gas commodity derivative positions. We diddo not designate any of our derivative instruments as hedges for accounting purposes and we record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative instruments expose us to the risk of financial loss in
somecertain circumstances, including when:
production is less than the volume covered by the derivative instruments;
the counter-partycounterparty to the derivative instrument defaults on its contractual obligations; or
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, our derivative arrangements limit the benefit we would receive from increases in the prices for crude oil and natural gas. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our
undeveloped crude oil and natural gas reserves. As part of our risk management program, we have hedged a significant portion of our forecasted
production through 2013.production. We utilize a combination of derivative contracts based on West Texas Intermediate
(“WTI”) crude oil pricing, Inter-Continental Exchange pricing for Brent crude oil, and Henry Hub pricing for natural gas. We believe our derivative contracts provide relevant protection from price fluctuations in the U.S. markets where we deliver and sell our production. The pricing for Brent crude oil is believed to be a better reflection of the sales prices
currently being realized in certain
of our U.S. market centers. However, in the event Brent prices increase significantly, the prices realized in those U.S. market centers may no longer be reflective of Brent prices. In such a circumstance, we may incur significant
realized cash losses upon settling our crude oil derivative instruments. Such losses may be incurred without seeing a corresponding increase in revenues from higher realized prices on our physical sales of crude oil.
Our Chairman and Chief Executive Officer owns approximately 68% of our outstanding common stock, giving him influence and control in corporate transactions and other matters, including a sale of our Company.
As of December 31,
2011,2013, Harold G. Hamm, our Chairman and Chief Executive Officer, beneficially owned
123,159,048126,337,891 shares of our outstanding common stock representing approximately 68% of our outstanding common shares. As a result, Mr. Hamm is our controlling shareholder and will continue to be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other shareholders, the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. As controlling shareholder, Mr. Hamm could cause, delay or prevent a change of control of our Company. The interests of Mr. Hamm may not coincide with the interests of other holders of our common stock.
Several
affiliated companies controlled by Mr. Hamm
provide oilfield, gathering and processing, marketing and other services to us. We expect these transactions will continueare in the
futurebusiness of gathering, processing, and
marketing crude oil and natural gas or providing oilfield services in some of the areas where we have operations. We have historically entered, and expect to continue entering, into transactions from time to time with these affiliated companies if, after an independent review by our Audit Committee, it is determined such transactions are in the Company's best interests and are on terms no less favorable to us than could be achieved with an unaffiliated third party. These transactions may result in conflicts of interest between Mr. Hamm’s affiliated companies and us. We can provide no assurance that any such conflicts will be resolved in our favor.
We may be subject to risks in connection with acquisitions.
The successful acquisition of producing properties requires an assessment of several factors, including:
future crude oil and natural gas prices and their appropriate differentials;
future development costs, operating costs and property taxes; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and
capabilities.capabilities prior to acquisition. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller
of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees and business associates, perform compliance reporting and in many other activities related to our business. Our business associates, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks, and those of our business associates may be subject to risks as a resultbecome the target of cyber attacks targetingor information security breaches, which could lead to disruptions in critical systems, unauthorized release of confidential or protected information, corruption of data or other disruptions of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber attack involving our information systems and related infrastructure, used byor that of our business associates, could disrupt our business and negatively impact our operations in the following ways, among others:
unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas
industry.Computers control nearly allresources;
data corruption or operational disruption of the oil and gas production and distribution systemsinfrastructure could result in the U.S. and abroad, someloss of which are utilized to transport our production, to market. Aor accidental discharge;
a cyber attack directed at oilon a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects; and gas production and distribution systems
a cyber attack on a third party gathering, pipeline, or rail service provider could damage critical distribution and/or storage assets or the environment, delay or prevent deliveryus from marketing our production, resulting in a loss of productionrevenues.
These events could damage our reputation and lead to
markets and make it difficultfinancial losses from remedial actions, loss of business or
impossible to accurately account for production and settle transactions. The occurrence of such an attack against any of the aforementioned production and distribution systemspotential liability, which could have a material adverse effect on our financial condition,
and results of
operations.operations or cash flows.
To date we have not experienced any material losses relating to cyber attacks; however, there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
| |
| Item 1B. | Unresolved Staff Comments |
There were no unresolved Securities and Exchange Commission staff comments at December 31,
2011.2013.The information required by Item 2 is contained inPart I, Item 1. Business—Crude Oil and Natural Gas Operations.
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
has commencedis ongoing and information and documents
are beingcontinue 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
givendue 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
such asincluding, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and
similarother matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material
adverse effect on its financial condition, results of operations or cash flows.
| |
| Item 4. | Mine Safety Disclosures |
| |
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Our common stock is listed on the New York Stock Exchange and trades under the symbol “CLR.” The following table sets forth quarterly high and low sales prices for each quarter of the previous two years. No cash dividends were declared during the previous two years. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2011 | | | 2010 | |
| | | Quarter Ended | | | Quarter Ended | |
| | | March 31 | | | June 30 | | | September 30 | | | December 31 | | | March 31 | | | June 30 | | | September 30 | | | December 31 | |
High | | $ | 73.48 | | | $ | 72.73 | | | $ | 71.77 | | | $ | 72.98 | | | $ | 46.18 | | | $ | 52.53 | | | $ | 48.65 | | | $ | 59.98 | |
Low | | | 56.55 | | | | 57.89 | | | | 46.25 | | | | 42.43 | | | | 36.27 | | | | 39.35 | | | | 38.23 | | | | 45.00 | |
Cash Dividend | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
Our
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2013 | | 2012 |
| | | Quarter Ended | | Quarter Ended |
| | | March 31 | | June 30 | | September 30 | | December 31 | | March 31 | | June 30 | | September 30 | | December 31 |
| High | | $ | 93.99 |
| | $ | 89.63 |
| | $ | 108.19 |
| | $ | 121.78 |
| | $ | 97.19 |
| | $ | 91.82 |
| | $ | 84.19 |
| | $ | 80.59 |
|
| Low | | $ | 74.03 |
| | $ | 72.35 |
| | $ | 86.56 |
| | $ | 100.25 |
| | $ | 67.94 |
| | $ | 61.50 |
| | $ | 61.02 |
| | $ | 66.07 |
|
| Cash Dividend | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Certain of our senior
notesnote indentures restrict the payment of dividends under certain circumstances and we do not anticipate paying any cash dividends on our common stock in the foreseeable future. As of February
15, 2012,17, 2014, the number of record holders of our common stock was
148.126. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately
48,500.57,200. On February
15, 2012,17, 2014, the last reported sales price of our
Common Stock,common stock, as reported on the New York Stock Exchange, was
$82.95$113.27 per share.
The following table summarizes our purchases of our common stock during the quarter ended December 31,
2011: | | | | | | | | | | | | | | | | |
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 program (3) | |
October 1, 2011 to October 31, 2011 | | | 39,413 | | | $ | 48.76 | | | | — | | | | — | |
November 1, 2011 to November 30, 2011 | | | 18,602 | | | $ | 66.26 | | | | — | | | | — | |
December 1, 2011 to December 31, 2011 | | | 1,499 | | | $ | 71.66 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
Total | | | 59,514 | | | $ | 54.81 | | | | — | | | | — | |
|
| | | | | | | | | | | | | |
| Period | | Total number of
shares purchased | | Average
price paid
per share | | 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) |
| October 1, 2013 to October 31, 2013 | | — |
| | — |
| | — |
| | — |
|
| November 1, 2013 to November 30, 2013 | | 92,303 |
| (1) | $ | 116.45 |
| (1) | — |
| | — |
|
| December 1, 2013 to December 31, 2013 | | 41,000 |
| (2) | $ | 102.20 |
| (2) | — |
| | — |
|
| Total | | 133,303 |
| | $ | 112.07 |
| | — |
| | — |
|
| |
| (1) | In connection with stock option exercises or restricted stock grants under the Continental Resources, Inc. 2000 Stock Option Plan (“2000 Plan”) and the Continental Resources, Inc.Company's 2005 Long-Term Incentive Plan (“("2005 Plan”Plan") and 2013 Long-Term Incentive Plan ("2013 Plan"), we adopted a policy that enables employees to surrender shares to cover their tax liability. AllEffective May 23, 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. The 92,303 shares purchased above represent shares surrendered by employees 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 of exercise or the date the restrictions lapsed on such shares, as applicable.shares. We paid the associated taxes to the Internal Revenue Service. |
| |
| (2) | Represents shares of our common stock purchased by Harold G. Hamm, our Chairman, Chief Executive Officer, and controlling shareholder in an open-market transaction on December 11, 2013. |
| |
| (3) | We are unable to determine at this time the total amount of securities or approximate dollar value of those 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 exercise of options or vesting of restrictions on shares under the 2000 Plan and 2005 Plan.shares. |
Equity Compensation Plan Information
The following table sets forth the information as of December 31,
20112013 relating to equity compensation plans:
| | | | | | | | | | | | |
| | | Number of Shares
to be Issued Upon
Exercise of
Outstanding
Options (1) | | | Weighted-Average
Exercise Price of
Outstanding Options | | | Remaining Shares
Available for Future
Issuance Under Equity
Compensation Plans (2) | |
Equity Compensation Plans Approved by Shareholders | | | 86,500 | | | $ | 0.71 | | | | 2,631,287 | |
Equity Compensation Plans Not Approved by Shareholders | | | — | | | | — | | | | — | |
|
| | | | | | | | | |
| | Number of Shares
to be Issued Upon
Exercise of
Outstanding
Options | | Weighted-Average
Exercise Price of
Outstanding Options | | Remaining Shares
Available for Future
Issuance Under Equity
Compensation Plans (1) |
| Equity Compensation Plans Approved by Shareholders | | — |
| | — |
| | 9,813,989 |
|
| Equity Compensation Plans Not Approved by Shareholders | | — |
| | — |
| | — |
|
| |
| (1) | All shares to be issued pursuant toRepresents the exercise of outstanding options are issuable pursuant to the 2000 Plan. |
(2) | Allmaximum remaining shares (2,631,287) are available for issuance under the 20052013 Plan. |
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on our common stock performance with the cumulative total returnsperformance of the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the groupDow Jones US Oil and Gas Index (“Dow Jones US O&G Index”) for the period of companiesDecember 2008 through December 2013. The graph assumes the value of the investment in our peer group as outlined below. common stock and in each index was $100 on December 31, 2008 and that any dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.
The information provided in this section is being furnished to, and not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.
As required by those rules, the performance graph was prepared based upon the following assumptions:$100 was invested in our common stock at its initial public offering price of $15 per share and was invested in the S&P 500 Index and our “peer group” on May 14, 2007 (our initial public offering date) at the closing price on such date;
investment in our peer group was weighted based on the stock price of each individual company within the peer group at the beginning of the period; and
dividends were reinvested on the relevant payment dates.
Our peer group is comprised of Cabot Oil & Gas Corporation, Cimarex Energy Co., Concho Resources Inc., Denbury Resources Inc., Forest Oil Corporation, Newfield Exploration Company, Pioneer Natural Resources Company, Range Resources Corporation, Ultra Petroleum Corp., and Whiting Petroleum Corporation. We selected these companies because they are publicly traded exploration and production companies similar in size and operations to us.
| |
| Item 6. | Selected Financial Data |
This section presents our selected
historical and pro forma consolidated financial
data.data for the years ended December 31, 2009 through 2013. The selected
historical consolidated financial data presented below is not intended to replace our
historical consolidated financial statements.
The following historical consolidated financial data, as it relates to each of the fiscal years ended December 31, 20072009 through 2011,2013, has been derived from our audited historical consolidated financial statements for such periods. You should read the following selected historical consolidated financial data in connection withPart II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and our historical consolidated financial statements and related notes included elsewhere in this report. The selected historical consolidated results are not necessarily indicative of results to be expected in future periods. | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
Income Statement data | | | | |
(in thousands, except per share data) | | | | |
Crude oil and natural gas sales | | $ | 1,647,419 | | | $ | 948,524 | | | $ | 610,698 | | | $ | 939,906 | | | $ | 606,514 | |
Loss on derivative instruments, net (1) | | | (30,049 | ) | | | (130,762 | ) | | | (1,520 | ) | | | (7,966 | ) | | | (44,869 | ) |
Total revenues | | | 1,649,789 | | | | 839,065 | | | | 626,211 | | | | 960,490 | | | | 582,215 | |
Income from continuing operations | | | 429,072 | | | | 168,255 | | | | 71,338 | | | | 320,950 | | | | 28,580 | |
Net Income | | | 429,072 | | | | 168,255 | | | | 71,338 | | | | 320,950 | | | | 28,580 | |
Basic earnings per share: | | | | | | | | | | | | | | | | | | | | |
From continuing operations | | $ | 2.42 | | | $ | 1.00 | | | $ | 0.42 | | | $ | 1.91 | | | $ | 0.17 | |
Net income per share | | $ | 2.42 | | | $ | 1.00 | | | $ | 0.42 | | | $ | 1.91 | | | $ | 0.17 | |
Shares used in basic earnings per share | | | 177,590 | | | | 168,985 | | | | 168,559 | | | | 168,087 | | | | 164,059 | |
Diluted earnings per share: | | | | | | | | | | | | | | | | | | | | |
From continuing operations | | $ | 2.41 | | | $ | 0.99 | | | $ | 0.42 | | | $ | 1.89 | | | $ | 0.17 | |
Net income per share | | $ | 2.41 | | | $ | 0.99 | | | $ | 0.42 | | | $ | 1.89 | | | $ | 0.17 | |
Shares used in diluted earnings per share | | | 178,230 | | | | 169,779 | | | | 169,529 | | | | 169,392 | | | | 165,422 | |
Pro forma C-corporation (2) | | | | | | | | | | | | | | | | | | | | |
Pro forma income from continuing operations | | | | | | | | | | | | | | | | | | $ | 184,002 | |
Pro forma net income | | | | | | | | | | | | | | | | | | | 184,002 | |
Pro forma basic earnings per share | | | | | | | | | | | | | | | | | | | 1.12 | |
Pro forma diluted earnings per share | | | | | | | | | | | | | | | | | | | 1.11 | |
Production | | | | | | | | | | | | | | | | | | | | |
Crude oil (MBbl) (3) | | | 16,469 | | | | 11,820 | | | | 10,022 | | | | 9,147 | | | | 8,699 | |
Natural gas (MMcf) | | | 36,671 | | | | 23,943 | | | | 21,606 | | | | 17,151 | | | | 11,534 | |
Crude oil equivalents (MBoe) | | | 22,581 | | | | 15,811 | | | | 13,623 | | | | 12,006 | | | | 10,621 | |
Average sales prices(4) | | | | | | | | | | | | | | | | | | | | |
Crude oil ($/Bbl) | | $ | 88.51 | | | $ | 70.69 | | | $ | 54.44 | | | $ | 88.87 | | | $ | 63.55 | |
Natural gas ($/Mcf) | | | 5.24 | | | | 4.49 | | | | 3.22 | | | | 6.90 | | | | 5.87 | |
Crude oil equivalents ($/Boe) | | | 73.05 | | | | 59.70 | | | | 45.10 | | | | 77.66 | | | | 58.31 | |
Average costs per Boe($/Boe) (4) | | | | | | | | | | | | | | | | | | | | |
Production expenses | | $ | 6.13 | | | $ | 5.87 | | | $ | 6.89 | | | $ | 8.40 | | | $ | 7.35 | |
Production taxes and other expenses | | | 6.42 | | | | 4.82 | | | | 3.37 | | | | 4.84 | | | | 3.13 | |
Depreciation, depletion, amortization and accretion | | | 17.33 | | | | 15.33 | | | | 15.34 | | | | 12.30 | | | | 9.00 | |
General and administrative expenses (5) | | | 3.23 | | | | 3.09 | | | | 3.03 | | | | 2.95 | | | | 3.15 | |
Proved reserves at December 31 | | | | | | | | | | | | | | | | | | | | |
Crude oil (MBbl) | | | 326,133 | | | | 224,784 | | | | 173,280 | | | | 106,239 | | | | 104,145 | |
Natural gas (MMcf) | | | 1,093,832 | | | | 839,568 | | | | 504,080 | | | | 318,138 | | | | 182,819 | |
Crude oil equivalents (MBoe) | | | 508,438 | | | | 364,712 | | | | 257,293 | | | | 159,262 | | | | 134,615 | |
Other financial data(in thousands) | | | | | | | | | | | | | | | | | | | | |
Net cash provided by operations | | $ | 1,067,915 | | | $ | 653,167 | | | $ | 372,986 | | | $ | 719,915 | | | $ | 390,648 | |
Net cash used in investing activities | | | (2,004,714 | ) | | | (1,039,416 | ) | | | (499,822 | ) | | | (927,617 | ) | | | (483,498 | ) |
Net cash provided by financing activities | | | 982,427 | | | | 379,943 | | | | 135,829 | | | | 204,170 | | | | 94,568 | |
EBITDAX (6) | | | 1,303,959 | | | | 810,877 | | | | 450,648 | | | | 757,708 | | | | 469,885 | |
Capital expenditures | | | 2,224,096 | | | | 1,237,189 | | | | 433,991 | | | | 988,593 | | | | 525,677 | |
Cash dividends per share | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 0.33 | |
Balance Sheet data at December 31(in thousands) | | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 5,646,086 | | | $ | 3,591,785 | | | $ | 2,314,927 | | | $ | 2,215,879 | | | $ | 1,365,173 | |
Long-term debt, including current maturities | | | 1,254,301 | | | | 925,991 | | | | 523,524 | | | | 376,400 | | | | 165,000 | |
Shareholders’ equity | | | 2,308,126 | | | | 1,208,155 | | | | 1,030,279 | | | | 948,708 | | | | 623,132 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2013 | | 2012 | | 2011 | | 2010 | | 2009 |
| Income Statement data | | | | | | | | | | |
| In thousands, except per share data | | |
| Crude oil and natural gas sales | | $ | 3,606,774 |
| | $ | 2,379,433 |
| | $ | 1,647,419 |
| | $ | 948,524 |
| | $ | 610,698 |
|
| Gain (loss) on derivative instruments, net (1) | | (191,751 | ) | | 154,016 |
| | (30,049 | ) | | (130,762 | ) | | (1,520 | ) |
| Total revenues | | 3,455,150 |
| | 2,572,520 |
| | 1,649,789 |
| | 839,065 |
| | 626,211 |
|
| Income from continuing operations | | 764,219 |
| | 739,385 |
| | 429,072 |
| | 168,255 |
| | 71,338 |
|
| Net income | | 764,219 |
| | 739,385 |
| | 429,072 |
| | 168,255 |
| | 71,338 |
|
| Basic earnings per share: | | | | | | | | | | |
| From continuing operations | | $ | 4.15 |
| | $ | 4.08 |
| | $ | 2.42 |
| | $ | 1.00 |
| | $ | 0.42 |
|
| Net income per share | | $ | 4.15 |
| | $ | 4.08 |
| | $ | 2.42 |
| | $ | 1.00 |
| | $ | 0.42 |
|
| Shares used in basic earnings per share | | 184,075 |
| | 181,340 |
| | 177,590 |
| | 168,985 |
| | 168,559 |
|
| Diluted earnings per share: | | | | | | | | | | |
| From continuing operations | | $ | 4.13 |
| | $ | 4.07 |
| | $ | 2.41 |
| | $ | 0.99 |
| | $ | 0.42 |
|
| Net income per share | | $ | 4.13 |
| | $ | 4.07 |
| | $ | 2.41 |
| | $ | 0.99 |
| | $ | 0.42 |
|
| Shares used in diluted earnings per share | | 184,849 |
| | 181,846 |
| | 178,230 |
| | 169,779 |
| | 169,529 |
|
| Production | | | | | | | | | | |
| Crude oil (MBbl) (2) | | 34,989 |
| | 25,070 |
| | 16,469 |
| | 11,820 |
| | 10,022 |
|
| Natural gas (MMcf) | | 87,730 |
| | 63,875 |
| | 36,671 |
| | 23,943 |
| | 21,606 |
|
| Crude oil equivalents (MBoe) | | 49,610 |
| | 35,716 |
| | 22,581 |
| | 15,811 |
| | 13,623 |
|
| Average sales prices (3) | | | | | | | | | | |
| Crude oil ($/Bbl) | | $ | 89.93 |
| | $ | 84.59 |
| | $ | 88.51 |
| | $ | 70.69 |
| | $ | 54.44 |
|
| Natural gas ($/Mcf) | | 5.25 |
| | 4.20 |
| | 5.24 |
| | 4.49 |
| | 3.22 |
|
| Crude oil equivalents ($/Boe) | | 72.71 |
| | 66.83 |
| | 73.05 |
| | 59.70 |
| | 45.10 |
|
| Average costs per Boe ($/Boe) (3) | | | | | | | | | | |
| Production expenses | | $ | 5.69 |
| | $ | 5.49 |
| | $ | 6.13 |
| | $ | 5.87 |
| | $ | 6.89 |
|
| Production taxes and other expenses | | 6.69 |
| | 6.42 |
| | 6.42 |
| | 4.82 |
| | 3.37 |
|
| Depreciation, depletion, amortization and accretion | | 19.47 |
| | 19.44 |
| | 17.33 |
| | 15.33 |
| | 15.34 |
|
| General and administrative expenses (4) | | 2.91 |
| | 3.42 |
| | 3.23 |
| | 3.09 |
| | 3.03 |
|
| Proved reserves at December 31 | | | | | | | | | | |
| Crude oil (MBbl) | | 737,788 |
| | 561,163 |
| | 326,133 |
| | 224,784 |
| | 173,280 |
|
| Natural gas (MMcf) | | 2,078,020 |
| | 1,341,084 |
| | 1,093,832 |
| | 839,568 |
| | 504,080 |
|
| Crude oil equivalents (MBoe) | | 1,084,125 |
| | 784,677 |
| | 508,438 |
| | 364,712 |
| | 257,293 |
|
| Other financial data (in thousands) | | | | | | | | | | |
| Net cash provided by operating activities | | $ | 2,563,295 |
| | $ | 1,632,065 |
| | $ | 1,067,915 |
| | $ | 653,167 |
| | $ | 372,986 |
|
| Net cash used in investing activities | | (3,711,011 | ) | | (3,903,370 | ) | | (2,004,714 | ) | | (1,039,416 | ) | | (499,822 | ) |
| Net cash provided by financing activities | | 1,140,469 |
| | 2,253,490 |
| | 982,427 |
| | 379,943 |
| | 135,829 |
|
| EBITDAX (5) | | 2,839,510 |
| | 1,963,123 |
| | 1,303,959 |
| | 810,877 |
| | 450,648 |
|
| Total capital expenditures | | 3,841,633 |
| | 4,358,572 |
| | 2,224,096 |
| | 1,237,189 |
| | 433,991 |
|
| Balance Sheet data at December 31 (in thousands) | | | | | | | | | | |
| Total assets | | $ | 11,941,182 |
| | $ | 9,140,009 |
| | $ | 5,646,086 |
| | $ | 3,591,785 |
| | $ | 2,314,927 |
|
| Long-term debt, including current maturities | | 4,715,832 |
| | 3,539,721 |
| | 1,254,301 |
| | 925,991 |
| | 523,524 |
|
| Shareholders’ equity | | 3,953,118 |
| | 3,163,699 |
| | 2,308,126 |
| | 1,208,155 |
| | 1,030,279 |
|
| |
| (1) | Derivative instruments are not designated as hedges for accounting purposes and, therefore, realized and unrealized changes in the fair value of the instruments are shown separately from crude oil and natural gas sales. The amounts above include unrealized non-cash mark-to-market gains (losses) on derivative instruments of ($130.2) million, $199.7 million, $4.1 million, ($166.2) million ($2.1) million and ($26.7)2.1) million for the years ended December 31, 2013, 2012, 2011, 2010, and 2009, and 2007, respectively. There were no unrealized gains or losses on derivative instruments for the year ended December 31, 2008. |
(2) | Prior to our initial public offering on May 14, 2007, we were a subchapter S corporation and income taxes were payable by our shareholders. In connection with our initial public offering, we converted to a subchapter C corporation. Pro forma adjustments are reflected to provide for income taxes as if we had been a subchapter C corporation for the applicable period presented. A statutory Federal tax rate of 35% and effective state tax rate of 3% (net of Federal income tax effects) were used for the pro forma enacted tax rate for the applicable pro forma period presented. |
(3)(2) | At various times, we have stored crude oil due to pipeline line fill requirements, low commodity prices, or transportation constraints or we have sold crude oil from inventory. These actions result in differences between our produced and sold crude oil volumes. For the year2013, crude oil sales volumes were 4 MBbls less than crude oil production volumes. For 2012, crude oil sales volumes were 112 MBbls less than crude oil production volumes. For 2011, crude oil sales volumes were 30 MBbls less than crude oil production volumes. For the year 2010, crude oil sales volumes were 78 MBbls more than crude oil production volumes. For the year 2009, crude oil sales volumes were 82 MBbls less than crude oil production volumes. For the year 2008, crude oil sales volumes were 97 MBbls more than crude oil production volumes. For the year 2007, crude oil sales volumes were 221 MBbls less than crude oil production volumes. |
(4) | |
| (3) | Average sales prices and average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions. |
(5) | |
| (4) | General and administrative expenses ($/Boe) include non-cash equity compensation expenseexpenses of $0.80 per Boe, $0.82 per Boe, $0.73 per Boe, $0.74 per Boe $0.84 per Boe, $0.75 per Boe and $1.23$0.84 per Boe for the years ended December 31, 2013, 2012, 2011, 2010, and 2009, 2008respectively. Additionally, general and 2007, respectively.administrative expenses include corporate relocation expenses of $0.04 per Boe, $0.22 per Boe and $0.14 per Boe for the years ended December 31, 2013, 2012 and 2011. No corporate relocation expenses were incurred prior to 2011. |
(6) | |
| (5) | EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivativenon-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 generally accepted accounting principles. A reconciliationReconciliations of net income and operating cash flows to EBITDAX isare provided inPart II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures. |
| |
| ITEM 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data included elsewhere in this report. Our operating results for the periods discussed below may not be indicative of future performance. For aadditional discussion of crude oil and natural gas reserve information, please seePart I, Item 1. Business—Crude Oil and Natural Gas Operations. The following discussion and analysis includes forward-looking statements and should be read in conjunction withPart I, Item 1A. Risk Factors in this report, along withCautionary Statement Regarding Forward-Looking Statementsfor 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
OverviewWe are engaged inan independent crude oil and natural gas exploration development and production activitiescompany 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 riverRiver and includes North Dakota Bakken, Montana Bakken, and the Red River units and the Niobrara play in Colorado and Wyoming.units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi riverRiver including various plays in the Anadarko WoodfordSouth Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma Woodford plays inareas of Oklahoma. The East region contains propertiesis comprised of undeveloped leasehold acreage east of the Mississippi river includingRiver. In December 2012, we sold the Illinois Basinproducing crude oil and natural gas properties in our East region. The sold properties represented an immaterial portion of our operations and do not materially affect the statecomparability of Michigan.
the operating results and cash flows for the periods presented in this report. Our operations are geographically concentrated in the North region, with that region comprising approximately 77% of our crude oil and natural gas production and approximately 86% of our crude oil and natural gas revenues for the year ended December 31, 2013.
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
stimulationstimulation) and enhanced recovery technologies provide the means to economically develop and produce crude oil and natural gas reserves from unconventional formations. We
derive the majority of our operating income and cash flows from the sale of crude oil and natural gas. We expect
that 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.
In recent months and years, there has been significant volatility in crude oil and natural gas prices due to a variety of factors we cannot control or predict, including political and economic events, weather conditions, and competition from other energy sources. These factors impact supply and demand for crude oil and natural gas, which affect crude oil and natural gas prices. In addition, the prices we realize for our crude oil and natural gas production are affected by price differences in the markets where we deliver our production. 2013 Highlights
Proved reserves
At December 31, 2011,2013, our estimated proved reserves totaled 508.41,084.1 MMBoe, an increase of 39%38% over proved reserves of 364.7784.7 MMBoe at December 31, 2010. The increase was2012. Extensions and discoveries resulting from our exploration and development activities were the primary drivers of our proved reserves growth in 2013, adding 444.7 MMBoe of proved reserves during the year. Our extensions and discoveries were primarily driven by successful drilling results and strong production growth in North Dakotathe Bakken field and the Anadarko Woodfordemerging SCOOP play. Our proved reserves in the Bakken field totaled 741.1 MMBoe at December 31, 2013, representing a 32% increase from 563.6 MMBoe at year-end 2012. Proved reserves in the SCOOP play of Oklahoma, coupled with higherincreased 241% from 62.9 MMBoe at December 31, 2012 to 214.7 MMBoe at December 31, 2013. The year 2013 was an impactful year for SCOOP as our drilling results and results from others in the industry have helped establish a crude oil pricesand liquids-rich natural gas productive fairway that has resulted in 2011. Extensions and discoveries in our key operating areas were partially offset by the removalbooking of 24.2 MMBoe of proved undevelopedadditional reserves primarily resulting from management’s decision to defer drilling on certain dry gasthis emerging play.
Our properties in the
Arkoma Woodford play in Oklahoma given the current and projected prices for natural gas.The Bakken field comprised 58%68% of our proved reserves at December 31, 2011,2013, with the Anadarko Woodford and Arkoma Woodford playsSCOOP comprising 26%20% and the Red River units in North Dakota, South Dakota and Montana comprising 13%7%. The Bakken, SCOOP and Red River units comprised 72%, 8% and 10%, respectively, of our proved reserves at year-end 2012. Estimated proved developed producing reserves were 205.2404.8 MMBoe at December 31, 2011,2013, representing 40%37% of our total estimated proved reserves compared with 38%39% at year-end 2010. 2012.
Crude oil
reserves comprised
64%68%, or 737.8 MMBoe, of our
508.4 MMBoe of estimated proved reserves at December 31,
20112013 compared to
62%72% at December 31,
2010.2012. The decreased percentage of crude oil reserves at December 31, 2013 resulted from the significant increase in SCOOP reserves as a percentage of our total reserves during the year, which have a higher concentration of liquids-rich natural gas compared to our other operating areas such as the Bakken.
We seek to operate wells in which we own an
interest, andinterest. At December 31, 2013, we operated wells that accounted for
87% of our total proved reserves and 86% of our
PV-10 and 64% of our 3,255 gross wells as of December 31, 2011.PV-10. By controlling operations, we are able to more effectively manage the costs and timing of exploration and development of our properties, including the drilling and
fracture stimulationcompletion methods used.
Our Additionally, our business strategy has historically focused on reserve and production growth through exploration and development. development activities.
For the three-year period ended December 31,
2011,2013, we added
367,668 MBoe840.3 MMBoe of proved reserves through extensions
and discoveries, compared to 2,462 MBoe84.5 MMBoe added through acquisitions. During this three-year period, our production increased from 13,623 MBoe in 2009 to 22,581 MBoe in 2011. Proved reserve additions from all sources amounted to 166,307 MBoe for the year ended December 21, 2011, generating a reserve replacement rate of 736% for the year.
An aspect of our business strategy has been to acquire large undeveloped acreage positions in new or developing resource plays. As of December 31, 2011 we held 2,089,266 gross (1,229,425 net) undeveloped acres, including 604,009 net undeveloped acres in the Bakken field in Montana
Production, revenues and
North Dakota and 250,506 net undeveloped acres in the Oklahoma Woodford play. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than later entrants into a developing play.operating cash flows
For the year ended December 31, 2011,2013, our crude oil and natural gas production increased to 22,581totaled 49,610 MBoe (61,865(135,919 Boe per day), up 6,770representing a 39% increase from production of 35,716 MBoe or 43%, from(97,583 Boe per day) for the year ended December 31, 2010.2012. Crude oil accounted for 73%represented 71% of our 2011 production. Crude2013 production compared to 70% for 2012.
Our crude oil and natural gas production was 6,920totaled 13,271 MBoe (144,254 Boe per day) for the fourth quarter of 2011,2013, a 13%2% increase over production of 6,09913,052 MBoe (141,873 Boe per day) for the third quarter of 20112013 and a 57%35% increase over production of 4,4199,829 MBoe (106,831 Boe per day) for the fourth quarter of 2010. 2012. Crude oil represented 70% of our production for the fourth quarter of 2013, 71% for the third quarter of 2013, and 72% for the fourth quarter of 2012.
The increase in 20112013 production was primarily driven by an increase inhigher production from our properties in the North Dakota Bakken field and the Anadarko WoodfordSCOOP play in Oklahoma due to the continued success of our drilling programs in those areas.
Our Bakken production in North Dakota increased to 9,73327,977 MBoe (76,649 Boe per day) for the year ended December 31, 2011,2013, a 90%50% increase over the comparable 20102012 period. Fourth quarter 20112013 production in the North Dakota Bakken field increased 99% overtotaled 7,394 MBoe (80,374 Boe per day), a 1% decrease from the third quarter of 2013 due to effects from adverse winter weather conditions and 36% higher than the fourth quarter of 2010. Our production2012.
Production in the
Anadarko Woodfordemerging SCOOP play
totalled 2,171totaled 6,910 MBoe
(18,932 Boe per day) for the year ended December 31,
2011, 367% higher than2013, a 318% increase over the
same period in 2010. Anadarko Woodfordcomparable 2012 period. SCOOP production
increased 476% intotaled 2,185 MBoe (23,754 Boe per day) for the 2013 fourth quarter, an 18% increase over the third quarter of 2013 and a 233% increase over the fourth quarter of
2011 compared to the fourth quarter of 2010.2012.
Our crude oil and natural gas revenues for the year ended December 31, 20112013 increased 74%52% to $1,647.4 million$3.61 billion due to a 22%39% increase in sales volumes and a 9% increase in realized commodity prices along with a 42% increase in sales volumes compared to the same period in 2010.2012. Our realized price per Boe increased $13.35$5.88 to $73.05$72.71 per Boe for the year ended December 31, 20112013 compared to the year ended December 31, 2010.2012 due to higher commodity prices and improved crude oil differentials realized. Crude oil accounted for 88%represented 87% of our total 20112013 crude oil and natural gas revenues compared to 89% for 2010.The differential between NYMEX calendar month average crude2012.
Crude oil
prices and
our realized crude oil price per barrel for the year ended December 31, 2011 was $6.39 compared to $9.02 for the year ended December 31, 2010. For the fourth quarter of 2011, the crude oil price differential was $5.00 per barrel, an improvement over a differential of $9.92 per barrelnatural gas revenues totaled $912.3 million for the fourth quarter of
2010. A significant portion2013, a 36% increase over revenues of $670.4 million for the 2012 fourth quarter due to a 36% increase in sales volumes, with realized prices being consistent between periods. Crude oil represented 85% of our
operatedtotal crude oil
production inand natural gas revenues for the
North region is being sold in markets other than Cushing, Oklahoma and is priced, apart from transportation costs, at a premiumfourth quarter of 2013 compared to
88% for the
West Texas Intermediate benchmark pricing in that market center, which has resulted in improved differentials.2012 fourth quarter.
Our cash flows from operating activities for the year ended December 31,
20112013 were
$1,067.9 million, an$2.56 billion, a 57% increase from
$653.2 million$1.63 billion provided by our operating activities during the comparable
20102012 period.
The increase inFor the fourth quarter of 2013, operating cash flows
wastotaled $584.8 million, 21% higher than operating cash flows of $484.2 million for the 2012 fourth quarter. The increased operating cash flows in 2013 were primarily due to
increasedhigher crude oil and natural gas revenues
as a result ofresulting mainly from increased
commodity prices and sales volumes, partially offset by an increase in
realizedcash losses on
matured derivatives and higher production expenses, production taxes, general and administrative expenses,
interest expense and other expenses associated with the growth of our operations
in 2011.over the past year.
Capital expenditures
Our capital expenditures budget for 20112013 was $2.0$3.60 billion excluding property acquisitions which wereare not provided for in our budget. Duringbudgeted. For the year ended December 31, 2011,2013, we invested $2,046.1 millionapproximately $3.57 billion in our capital program (including increased accruals for capital expenditures(excluding $268.1 million of $173.6 millionunbudgeted acquisitions and $14.9including $28.4 million of seismic costs and excluding unbudgeted property acquisitions)$89.5 million of capital costs associated with increased accruals for capital expenditures). During 2011, we invested $178 million in unbudgeted leasehold and producing property acquisitions, resulting in total capitalCapital expenditures of $2,224.1 million for the year.fourth quarter of 2013 totaled $867.5 million, excluding $71.2 million of unbudgeted acquisitions. Our 20112013 capital program focused primarily on increased exploration and development activity in the Bakken field of North Dakota and MontanaSCOOP play.
Through leasing and
the Anadarko Woodford playacquisitions in
Oklahoma.In November 2011,2013, we increased our Board of Directors approved aBakken acreage by 6% from 1,139,803 net acres at year-end 2012 to 1,209,821 net acres at year-end 2013 and increased our SCOOP acreage by 85% from 218,167 net acres at year-end 2012 to 403,854 net acres at year-end 2013.
Our capital expenditures budget
of $1.75 billion.for 2014 is $4.05 billion, excluding acquisitions. Our
20122014 capital program
willis expected to continue
to focusfocusing on
exploratory and development drilling in the Bakken
field and
Anadarko Woodford plays. In 2012, weSCOOP play. We expect to
participate continue participating as a buyer of properties whenif and ifwhen we have the ability to increase our position in strategic plays at favorablecompetitive terms. Potential acquisition expenditures
We economically hedge a portion of our anticipated future production to achieve more predictable cash flows and reduce our exposure to fluctuations in commodity prices. Reducing our exposure to price volatility helps ensure adequate funds are
not budgeted.In January 2012 we requested, and were granted by the lenders, an increase in our credit facility’s aggregate commitments from $750 million to $1.25 billion, effective January 31, 2012. Our borrowing base of $2.25 billion and all other substantive terms of the credit facility remained unchanged. The increased commitment level will provide additional available liquidity if needed to maintain our growth strategy, take advantage of business opportunities, and fundfor our capital program.
Due to the volatility of crude oil and natural gas prices and our desire to develop our substantial inventory of undeveloped reserves as part of our capital program, we have hedged a substantial portion of our forecasted production from our estimated proved reserves through 2013. We expect our cash flows from operations, our remaining cash balance, and the availability of our credit facility, including our ability to increase our borrowing capacity thereunder, will be sufficient to meet our budgeted capital expenditure needs for the next 12 months.
How We Evaluate Our Operations
months; however, we may choose to access the capital markets for additional financing to take advantage of business opportunities that may arise if such financing can be arranged at favorable terms.
Credit facility release of collateral
In November 2013, following an upgrade by Standard & Poor’s Rating Services (“S&P”), as permitted by the credit facility terms, we provided the lenders under our credit facility notice of our intention to elect an Additional Covenant Period (as defined in the credit facility). The election of an Additional Covenant Period means that the credit facility is not currently subject to a borrowing base. The election was made in order to facilitate the release of collateral consisting of oil and gas properties securing obligations under the credit facility. On December 11, 2013, we delivered notice to the credit facility lenders confirming we had satisfied all conditions for releasing the collateral and the release of such collateral became effective as of December 12, 2013. On December 13, 2013 our credit rating was upgraded by Moody's Investor Services, Inc. (“Moody’s”). As a result of the second upgrade, we are not currently required to: (i) comply with certain reporting requirements; and (ii) maintain a ratio of the present value of oil and gas properties to total funded debt of not less than 1.5 to 1.0, as set forth in the credit facility.
Financial and operating highlights
We use a variety of financial and operating measures to
evaluate our operations and assess our performance. Among these measures are:
volumesVolumes of crude oil and natural gas produced;
produced,crudeCrude oil and natural gas prices realized;
realized,perPer unit operating and administrative costs;costs, and
EBITDAX (a non-GAAP financial measure).
The following table contains financial and operating highlights for the periods presented. | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
Average daily production: | | | | | | | | | | | | |
Crude oil (Bbl per day) | | | 45,121 | | | | 32,385 | | | | 27,459 | |
Natural gas (Mcf per day) | | | 100,469 | | | | 65,598 | | | | 59,194 | |
Crude oil equivalents (Boe per day) | | | 61,865 | | | | 43,318 | | | | 37,324 | |
Average sales prices: (1) | | | | | | | | | | | | |
Crude oil ($/Bbl) | | $ | 88.51 | | | $ | 70.69 | | | $ | 54.44 | |
Natural gas ($/Mcf) | | | 5.24 | | | | 4.49 | | | | 3.22 | |
Crude oil equivalents ($/Boe) | | | 73.05 | | | | 59.70 | | | | 45.10 | |
Production expenses ($/Boe) (1) | | | 6.13 | | | | 5.87 | | | | 6.89 | |
General and administrative expenses ($/Boe) (1) (2) | | | 3.23 | | | | 3.09 | | | | 3.03 | |
Net income (in thousands) | | | 429,072 | | | | 168,255 | | | | 71,338 | |
Diluted net income per share | | | 2.41 | | | | 0.99 | | | | 0.42 | |
EBITDAX (in thousands) (3) | | | 1,303,959 | | | | 810,877 | | | | 450,648 | |
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| Average daily production: | | | | | | |
| Crude oil (Bbl per day) | | 95,859 |
| | 68,497 |
| | 45,121 |
|
| Natural gas (Mcf per day) | | 240,355 |
| | 174,521 |
| | 100,469 |
|
| Crude oil equivalents (Boe per day) | | 135,919 |
| | 97,583 |
| | 61,865 |
|
| Average sales prices: (1) | | | | | | |
| Crude oil ($/Bbl) | | $ | 89.93 |
| | $ | 84.59 |
| | $ | 88.51 |
|
| Natural gas ($/Mcf) | | $ | 5.25 |
| | $ | 4.20 |
| | $ | 5.24 |
|
| Crude oil equivalents ($/Boe) | | $ | 72.71 |
| | $ | 66.83 |
| | $ | 73.05 |
|
| Production expenses ($/Boe) (1) | | $ | 5.69 |
| | $ | 5.49 |
| | $ | 6.13 |
|
| Production taxes (% of oil and gas revenues) | | 8.2 | % | | 8.2 | % | | 7.9 | % |
| DD&A ($/Boe) (1) | | $ | 19.47 |
| | $ | 19.44 |
| | $ | 17.33 |
|
| General and administrative expenses ($/Boe) (1) | | $ | 2.91 |
| | $ | 3.42 |
| | $ | 3.23 |
|
| Net income (in thousands) | | $ | 764,219 |
| | $ | 739,385 |
| | $ | 429,072 |
|
| Diluted net income per share | | $ | 4.13 |
| | $ | 4.07 |
| | $ | 2.41 |
|
| EBITDAX (in thousands) (2) | | $ | 2,839,510 |
| | $ | 1,963,123 |
| | $ | 1,303,959 |
|
| |
| (1) | Average sales prices and per unit expenses have been calculated using sales volumes and exclude any effect of derivative transactions. |
| |
| (2) | General and administrative expense ($/Boe) includes non-cash equity compensation expense of $0.73 per Boe, $0.74 per Boe, and $0.84 per Boe for the years ended December 31, 2011, 2010 and 2009, respectively. |
(3) | EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivativenon-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. A reconciliationReconciliations of net income and operating cash flows to EBITDAX isare provided subsequently under the headingNon-GAAP Financial Measures. |
The following table presents selected financial and operating information for each of the periods presented.
| | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | Dollars in thousands, except sales price data | |
Crude oil and natural gas sales | | $ | 1,647,419 | | | $ | 948,524 | | | $ | 610,698 | |
Loss on derivative instruments, net(1) | | | (30,049 | ) | | | (130,762 | ) | | | (1,520 | ) |
Total revenues | | | 1,649,789 | | | | 839,065 | | | | 626,211 | |
Operating costs and expenses(2) | | | 889,037 | | | | 528,744 | | | | 493,923 | |
Other expenses, net | | | 73,307 | | | | 51,854 | | | | 22,280 | |
| | | | | | | | | | | | |
Income before income taxes | | | 687,445 | | | | 258,467 | | | | 110,008 | |
Provision for income taxes | | | 258,373 | | | | 90,212 | | | | 38,670 | |
| | | | | | | | | | | | |
Net income | | $ | 429,072 | | | $ | 168,255 | | | $ | 71,338 | |
Production volumes: | | | | | | | | | | | | |
Crude oil (MBbl) (3) | | | 16,469 | | | | 11,820 | | | | 10,022 | |
Natural gas (MMcf) | | | 36,671 | | | | 23,943 | | | | 21,606 | |
Crude oil equivalents (MBoe) | | | 22,581 | | | | 15,811 | | | | 13,623 | |
Sales volumes: | | | | | | | | | | | | |
Crude oil (MBbl) (3) | | | 16,439 | | | | 11,898 | | | | 9,940 | |
Natural gas (MMcf) | | | 36,671 | | | | 23,943 | | | | 21,606 | |
Crude oil equivalents (MBoe) | | | 22,551 | | | | 15,889 | | | | 13,541 | |
Average sales prices:(4) | | | | | | | | | | | | |
Crude oil ($/Bbl) | | $ | 88.51 | | | $ | 70.69 | | | $ | 54.44 | |
Natural gas ($/Mcf) | | | 5.24 | | | | 4.49 | | | | 3.22 | |
Crude oil equivalents ($/Boe) | | | 73.05 | | | | 59.70 | | | | 45.10 | |
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| In thousands, except sales price data | | 2013 | | 2012 | | 2011 |
| Crude oil and natural gas sales | | $ | 3,606,774 |
| | $ | 2,379,433 |
| | $ | 1,647,419 |
|
| Gain (loss) on derivative instruments, net (1) | | (191,751 | ) | | 154,016 |
| | (30,049 | ) |
| Crude oil and natural gas service operations | | 40,127 |
| | 39,071 |
| | 32,419 |
|
| Total revenues | | 3,455,150 |
| | 2,572,520 |
| | 1,649,789 |
|
| Operating costs and expenses (2) | | (2,009,383 | ) | | (1,279,713 | ) | | (889,037 | ) |
| Other expenses, net | | (232,718 | ) | | (137,611 | ) | | (73,307 | ) |
| Income before income taxes | | 1,213,049 |
| | 1,155,196 |
| | 687,445 |
|
| Provision for income taxes | | (448,830 | ) | | (415,811 | ) | | (258,373 | ) |
| Net income | | $ | 764,219 |
| | $ | 739,385 |
| | $ | 429,072 |
|
| Production volumes: | | | | | | |
| Crude oil (MBbl) (3) | | 34,989 |
| | 25,070 |
| | 16,469 |
|
| Natural gas (MMcf) | | 87,730 |
| | 63,875 |
| | 36,671 |
|
| Crude oil equivalents (MBoe) | | 49,610 |
| | 35,716 |
| | 22,581 |
|
| Sales volumes: | | | | | | |
| Crude oil (MBbl) (3) | | 34,985 |
| | 24,958 |
| | 16,439 |
|
| Natural gas (MMcf) | | 87,730 |
| | 63,875 |
| | 36,671 |
|
| Crude oil equivalents (MBoe) | | 49,607 |
| | 35,604 |
| | 22,551 |
|
| Average sales prices: (4) | | | | | | |
| Crude oil ($/Bbl) | | $ | 89.93 |
| | $ | 84.59 |
| | $ | 88.51 |
|
| Natural gas ($/Mcf) | | 5.25 |
| | 4.20 |
| | 5.24 |
|
| Crude oil equivalents ($/Boe) | | 72.71 |
| | 66.83 |
| | 73.05 |
|
| |
| (1) | Amounts include an unrealizeda non-cash mark-to-market gainloss on derivative instruments of $4.1$130.2 million for the year ended December 31, 20112013 and unrealized non-cash mark-to-market lossesgains on derivative instruments of $166.2$199.7 million and $2.1$4.1 million for the years ended December 31, 20102012 and 2009,2011, respectively. |
| |
| (2) | NetAmounts are net of gaingains on salesales of assets of $20.8$0.1 million, $29.6$136.0 million, and $0.7$20.8 million for the years ended December 31, 2013, 2012 and 2011, 2010,respectively. See Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and 2009, respectively. In MarchDispositions for further discussion of 2011 we assigned certain non-strategic leaseholds in the state of Michigan to a third party for cash proceeds of $22.0 million and recognized a pre-tax gain on the transaction of $15.3 million. In June 2010, we sold certain non-strategic leaseholds located in Louisiana to a third party for cash proceeds of $35.4 million and recognized a pre-tax gain on the transaction of $31.7 million. These transactions involved undeveloped acreage with no proved reserves and no production or revenues.2012 dispositions. |
| |
| (3) | 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 4 MBbls less than crude oil production for the year ended December 31, 2013, 112 MBbls less than crude oil production for the year ended December 31, 2012 and 30 MBbls less than crude oil production for the year ended December 31, 2011, 78 MBbls more than crude oil production for the year ended December 31, 2010 and 82 MBbls less than crude oil production for the year ended December 31, 2009.2011. |
| |
| (4) | Average sales prices have been calculated using sales volumes and exclude any effect of derivative transactions. |
Year ended December 31, 20112013 compared to the year ended December 31, 20102012
The following tables reflect our production by product and region for the periods presented.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | | | | | |
| | | 2011 | | | 2010 | | | Volume
increase | | | Percent
increase | |
| | | Volume | | | Percent | | | Volume | | | Percent | | | |
Crude oil (MBbl) | | | 16,469 | | | | 73 | % | | | 11,820 | | | | 75 | % | | | 4,649 | | | | 39 | % |
Natural Gas (MMcf) | | | 36,671 | | | | 27 | % | | | 23,943 | | | | 25 | % | | | 12,728 | | | | 53 | % |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total (MBoe) | | | 22,581 | | | | 100 | % | | | 15,811 | | | | 100 | % | | | 6,770 | | | | 43 | % |
| | | |
| | | Year Ended December 31, | | | Volume
increase
(decrease) | | | Percent
increase
(decrease) | |
| | | 2011 | | | 2010 | | | |
| | | MBoe | | | Percent | | | MBoe | | | Percent | | | |
North Region | | | 17,462 | | | | 77 | % | | | 12,431 | | | | 79 | % | | | 5,031 | | | | 40 | % |
South Region | | | 4,705 | | | | 21 | % | | | 2,915 | | | | 18 | % | | | 1,790 | | | | 61 | % |
East Region | | | 414 | | | | 2 | % | | | 465 | | | | 3 | % | | | (51 | ) | | | (11 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 22,581 | | | | 100 | % | | | 15,811 | | | | 100 | % | | | 6,770 | | | | 43 | % |
|
| | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Volume
increase | | Volume
percent
increase |
| | | 2013 | | 2012 | |
| | | Volume | | Percent | | Volume | | Percent | |
| Crude oil (MBbl) | | 34,989 |
| | 71 | % | | 25,070 |
| | 70 | % | | 9,919 |
| | 40 | % |
| Natural Gas (MMcf) | | 87,730 |
| | 29 | % | | 63,875 |
| | 30 | % | | 23,855 |
| | 37 | % |
| Total (MBoe) | | 49,610 |
| | 100 | % | | 35,716 |
| | 100 | % | | 13,894 |
| | 39 | % |
|
| | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Volume
increase
(decrease) | | Percent
increase
(decrease) |
| | | 2013 | | 2012 | |
| | | MBoe | | Percent | | MBoe | | Percent | |
| North Region | | 38,023 |
| | 77 | % | | 27,207 |
| | 76 | % | | 10,816 |
| | 40 | % |
| South Region | | 11,587 |
| | 23 | % | | 8,110 |
| | 23 | % | | 3,477 |
| | 43 | % |
| East Region (1) | | — |
| | — |
| | 399 |
| | 1 | % | | (399 | ) | | (100 | %) |
| Total | | 49,610 |
| | 100 | % | | 35,716 |
| | 100 | % | | 13,894 |
| | 39 | % |
| |
| (1) | In December 2012, we sold the producing crude oil and natural gas properties in our East region and no new wells have been subsequently drilled in that region. Accordingly, no production is reflected for the East region for the year ended December 31, 2013. |
Crude oil production volumes increased 39% during9,919 MBbls, or 40%, for the year ended December 31, 20112013 compared to the year ended December 31, 2010.2012. Production increases in the Bakken field and the Anadarko WoodfordSCOOP play contributed incremental production volumes in 20112013 of 4,41010,661 MBbls, a 72%57% increase over production in these areas for the same period in 2010.2012. Production growth in these areas is primarily due to increased drilling activity and higher well completionscompletion activity resulting from our accelerated drilling program for 2011.program. These increases were partially offset by a decrease of 418 MBbls associated with non-strategic properties in Wyoming and the East region that were sold in February 2012 and December 2012, respectively. Additionally, production from our properties in the Cedar Hills field increased 203Red River units and Northwest Cana play decreased a total of 308 MBbls, or 5%, in 2011over the prior year due to new wells being completeda combination of natural declines in production and enhanced recovery techniques being successfully applied.reduced drilling activity in those areas.
Natural gas production volumes increased 12,72823,855 MMcf, or 53%, during the year ended December 31, 2011 compared to the same period in 2010. Natural gas production in the North Dakota Bakken field was up 3,529 MMcf, or 88%37%, for the year ended December 31, 20112013 compared to the same period in 20102012. Natural gas production in the Bakken field increased 11,299 MMcf, or 61%, for the year ended December 31, 2013 compared to the same period in 2012 due to new wells being completed and gas from existing wells being connected to natural gas processing plants in North Dakota. We expect natural gas production growth in North Dakota Bakken to be further enhanced by the increased capacity of natural gas processing plants in the play, which will enable us to deliver more natural gas to market.play. Natural gas production in the Anadarko WoodfordSCOOP play increased 8,97122,378 MMcf, or 366%317%, due to additional wells being completed and producing in the year ended December 31, 20112013 compared to the same period in 2010. Further, natural gas production increased 502 MMcf in non-Woodford areas of our South region due to the completion of new wells during the period.2012. These increases were partially offset by decreases in production volumes totaling 9,554 MMcf, or 27%, from our properties in Northwest Cana, Arkoma Woodford, and non-core areas in our South region due to a 498 MMcf decreasecombination of natural declines in production and reduced drilling activity. Additionally, natural gas production from our Arkoma Woodforddecreased 159 MMcf associated with non-strategic properties which consist primarily of dry gas. In 2011, we scaled back our Arkoma Woodford drilling program due toin Wyoming and the unfavorable pricing environment for natural gas, instead choosing to focus on the liquids-rich Anadarko Woodford play.East region that were sold in February 2012 and December 2012, respectively.
Our total revenues
are comprisedconsist of sales of crude oil and natural gas,
realizedgains and
unrealizedlosses resulting from changes in the fair value of our derivative instruments and revenues associated with crude oil and natural gas service operations.
Crude Oiloil and Natural Gas Sales.natural gas sales. Crude oil and natural gas sales for the year ended December 31, 20112013 were $1,647.4 million,$3.61 billion, a 74%52% increase from sales of $948.5 million$2.38 billion for the same period in 2010.2012. Our sales volumes increased 6,66214,003 MBoe, or 42%39%, over the same period in 20102012 primarily due to the continuing success of our drillingprograms in the North Dakota Bakken field and Anadarko WoodfordSCOOP play.
Our realized price per Boe increased $13.35$5.88 to $73.05$72.71 per Boe for the year ended December 31, 20112013 from $59.70$66.83 per Boe for the year ended December 31, 2010. 2012. This increase reflects higher crude oil and natural gas prices realized in connection with improved market prices along with an improvement in crude oil differentials.
The differential between NYMEX West Texas Intermediate ("WTI") calendar month average crude oil prices and our realized crude oil price per barrel for the year ended December 31, 20112013 was $6.39$8.23 compared to $9.02$9.06 for the year ended December 31, 2010. A significant portion of2012. The improved differential reflects our operatedcontinued efforts to shift Bakken crude oil sales to coastal markets in the United States with less dependence on currently available pipeline markets. We continue to employ a portfolio approach (rail and pipe) in transporting to multiple U.S. coastal and inland markets and expect this trend to continue in 2014. Rail transportation costs are typically higher than pipeline transportation costs per barrel mile, but market prices realized in U.S. coastal markets continue to be competitive with currently available pipeline markets. We plan to continue pursuing this portfolio approach to balance volumes delivered to pipeline and rail market destinations in an effort to maximize net wellhead value.
While our crude oil differentials in 2013 generally improved over levels experienced in 2012, they widened in recent months as Bakken production in the
North region is being sold in markets other than Cushing, OklahomaWilliston basin continued to grow and
is priced, apart from transportation costs, at a premium to West Texas Intermediate benchmark pricing, which hasseasonal refinery maintenance and outages resulted in
improved differentials.a temporary reduction in demand for Bakken crude oil. As a result, our realized crude oil differential to WTI averaged $13.05 per barrel in the fourth quarter of 2013 compared to $7.80 per barrel for the 2013 third quarter and $3.21 per barrel for the 2012 fourth quarter. The wide differentials realized in the 2013 fourth quarter are expected to continue into the first quarter of 2014. We expect crude oil differentials to ultimately improve from current levels but for volatility 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 realized and unrealized changes in fair value of derivative instruments in the consolidated statements of income under the caption “Loss“Gain (loss) on derivative instruments, net”, which is a component of total revenues.During
Changes in commodity prices during 2013 had an overall negative impact on the year ended December 31, 2011, we realized losses on crude oilfair value of our derivatives, which resulted in negative revenue adjustments of $71.4$191.8 million and realized gains on natural gas derivativesfor the year. We expect our revenues will continue to be significantly impacted, either positively or negatively, by changes in the fair value of $37.3 million. During the year ended December 31, 2011, we reported an unrealized non-cash mark-to-market gain on crude oil derivativesour derivative instruments as a result of $18.8 million and an unrealized non-cash mark-to-market loss on natural gas derivatives of $14.7 million. During the year ended December 31, 2010, we realized gains on crude oil derivatives of $13.2 million and natural gas derivatives of $22.3 million. During the year ended December 31, 2010, we reported an unrealized non-cash mark-to-market loss on crude oil derivatives of $186.0 million and an unrealized non-cash mark-to-market gain on natural gas derivatives of $19.8 million.Crude Oil and Natural Gas Service Operations. Ourvolatility in crude oil and natural gas service operations consist primarily ofprices.
The following table presents the treatmentimpact on total revenues related to cash settlements on matured derivative instruments and sale of lower quality crude oil, or reclaimed crude oil. The table below shows the volumesnon-cash gains and prices for the sale of reclaimed crude oillosses on open derivative instruments for the periods presented. | | | | | | | | | | | | |
| | | Year Ended December 31, | | | Variance | |
Reclaimed crude oil sales | | 2011 | | | 2010 | | |
Average sales price ($/Bbl) | | $ | 92.30 | | | $ | 69.35 | | | $ | 22.95 | |
Sales volumes (barrels) | | | 259,000 | | | | 227,000 | | | | 32,000 | |
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.
|
| | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 |
| Cash received (paid) on derivatives: | | | | |
| Crude oil derivatives | | $ | (71,156 | ) | | $ | (55,579 | ) |
| Natural gas derivatives | | 9,601 |
| | 9,858 |
|
| Cash paid on derivatives, net | | (61,555 | ) | | (45,721 | ) |
| Non-cash gain (loss) on derivatives | | | | |
| Crude oil derivatives | | (126,167 | ) | | 202,478 |
|
| Natural gas derivatives | | (4,029 | ) | | (2,741 | ) |
| Non-cash gain (loss) on derivatives, net | | (130,196 | ) | | 199,737 |
|
| Gain (loss) on derivative instruments, net | | $ | (191,751 | ) | | $ | 154,016 |
|
The average sales price for reclaimed crude oil sold from our central treating units was $22.95 per barrel highernon-cash mark-to-market gains and losses reflected above for the year ended December 31, 2011 than2013 relate to derivative instruments with various terms that are scheduled to mature over the comparable 2010 period. This contributedperiod from January 2014 to an increase in reclaimed crude oil revenue of $7.0 millionDecember 2015. Over this period, actual derivative settlements may differ significantly, either positively or negatively, from the mark-to-market valuation at December 31, 2013.
Operating Costs and Expenses
Production expenses and production taxes and other expenses. Production expenses increased 44% to $23.8 million and contributed to an overall increase in crude oil and natural gas service operations revenue of $11.1$282.2 million for the year ended December 31, 2011. Also contributing to the increase in crude oil and natural gas service operations revenue was a $3.32013 from $195.4 million increase in saltwater disposal income resulting from increased activity. Associated crude oil and natural gas service operations expenses increased $8.6 million to $26.7 million duringfor the year ended December 31, 2011 from $18.1 million during the year ended December 31, 2010 due mainly to an increase in the costs of purchasing and treating reclaimed crude oil for resale and in providing saltwater disposal services.Operating Costs and Expenses
Production Expenses and Production Taxes and Other Expenses. Production expenses increased 48% to $138.2 million during the year ended December 31, 2011 from $93.2 million during the year ended December 31, 2010.2012. This increase is primarily the result of higher production volumes from an increase in the number of producing wells.wells along with higher costs incurred in 2013 from severe weather conditions encountered in the North region which created a more challenging operating environment compared to a mild winter season experienced in 2012. Production expensesexpense per Boe increased to $6.13$5.69 for the year ended December 31, 2011 from $5.872013 compared to $5.49 per Boe for the year ended December 31, 2010. Contributing to the per-unit increase were increases in well site and road maintenance costs and saltwater disposal costs in the 2011 second quarter, all resulting from abnormal rainfall and flooding in North Dakota in April and May 2011. Also contributing to the per-unit increase were higher workover expenditures from increased activity as well as general inflationary pressure on the costs of oilfield services and equipment.2012.
Production taxes and other expenses increased $68.2$103.7 million, or 89%45%, to $144.8$332.1 million duringfor the year ended December 31, 20112013 compared to $228.4 million for the year ended December 31, 20102012 as a result of higher crude oil and natural gas revenues resulting from increased commodity prices and sales volumes along with the expiration of various tax incentives.and higher realized commodity prices. Production taxes and other expenses in the consolidated statements of income include other charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Oklahoma Woodford and North Dakota Bakken areas of $13.7$33.3 million and $6.1$29.9 million for the yearyears ended December 31, 20112013 and 2010,2012, respectively. The increase in other charges is primarily due to the significant increase inhigher natural gas sales volumes in 2011.2013. Production taxes, excluding other charges, as a percentage of crude oil and natural gas revenues were 7.9%8.2% for the yearboth years ended December 31, 2011 compared to 7.5% for the year ended December 31, 2010. The increase is due to the expiration of various tax incentives coupled with higher taxable revenues in North Dakota, our most active area, which has production tax rates of up to 11.5% of crude oil revenues.2013 and 2012. Production taxes are generally based on the wellhead values of production and vary by state. Additionally, someSome states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of crude oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana and Oklahoma, new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate reverts to the statutory rate. Our overall production tax rate is expected to further increase as we continue to expand our operations in North Dakota and as production tax incentives we currently receive for horizontal wells reach the end of their incentive periods.
On a unit of sales basis, production expenses and production taxes and other expenses were as follows:
| | | | | | | | |
| | | Year Ended December 31, | |
$/Boe | | 2011 | | | 2010 | |
Production expenses | | $ | 6.13 | | | $ | 5.87 | |
Production taxes and other expenses | | | 6.42 | | | | 4.82 | |
| | | | | | | | |
Production expenses, production taxes and other expenses | | $ | 12.55 | | | $ | 10.69 | |
|
| | | | | | | | |
| | | Year ended December 31, |
| $/Boe | | 2013 | | 2012 |
| Production expenses | | $ | 5.69 |
| | $ | 5.49 |
|
| Production taxes and other expenses | | 6.69 |
| | 6.42 |
|
| Production expenses, production taxes and other expenses | | $ | 12.38 |
| | $ | 11.91 |
|
Production expenses averaged $6.03 per Boe for the fourth quarter of 2013. The increase in the fourth quarter was due to higher costs incurred resulting from severe winter weather in the North region that created a challenging operating environment. The increased costs, coupled with delayed completions and reduced production from curtailed wells in North Dakota during that time, resulted in higher per-unit production expenses for the quarter.
Exploration Expensesexpenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. The following table shows the components of exploration expenses for the periods indicated. | | | | | | | | |
| | | Year Ended December 31, | |
(in thousands) | | 2011 | | | 2010 | |
Geological and geophysical costs | | $ | 19,971 | | | $ | 9,739 | |
Dry hole costs | | | 7,949 | | | | 3,024 | |
| | | | | | | | |
Exploration expenses | | $ | 27,920 | | | $ | 12,763 | |
Geological
|
| | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 |
| Exploratory geological and geophysical costs | | $ | 25,597 |
| | $ | 22,740 |
|
| Dry hole costs | | 9,350 |
| | 767 |
|
| Exploration expenses | | $ | 34,947 |
| | $ | 23,507 |
|
Exploratory geological and geophysical costs increased $10.2$2.9 million for the year ended December 31, 2013 due to changes in the timing and amount of acquisitions of exploratory seismic data between periods. Dry hole costs increased $8.6 million for the year ended December 31, 2013 and primarily reflect costs associated with exploratory wells in the Arkoma Woodford area and a non-Woodford area of our South region.
Depreciation, depletion, amortization and accretion (“DD&A”). Total DD&A increased $273.5 million, or 40%, for the year ended December 31, 2013 compared to the year ended December 31, 2012 primarily due to a 39% increase in sales volumes. The following table shows the components of our DD&A on a unit of sales basis.
|
| | | | | | | | |
| | | Year ended December 31, |
| $/Boe | | 2013 | | 2012 |
| Crude oil and natural gas properties | | $ | 19.17 |
| | $ | 19.10 |
|
| Other equipment | | 0.24 |
| | 0.25 |
|
| Asset retirement obligation accretion | | 0.06 |
| | 0.09 |
|
| Depreciation, depletion, amortization and accretion | | $ | 19.47 |
| | $ | 19.44 |
|
DD&A for crude oil and natural gas properties averaged $20.08 per Boe for the fourth quarter of 2013. Fourth quarter DD&A was impacted by the operational timing of pad drilling and resulting mix of well completions during the year.
Property impairments. Property impairments increased in the year ended December 31, 2013 by $98.2 million to $220.5 million compared to $122.3 million for the year ended December 31, 2012.
Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually insignificant non-producing properties are amortized on an aggregate basis based on our estimated experience of successful drilling and the average holding period. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis. Impairments of non-producing properties increased $50.8 million for the year ended December 31, 2013 to $168.7 million compared to $117.9 million for the year ended December 31, 2012. The increase primarily resulted from a larger base of amortizable costs in the current year coupled with higher rates of amortization resulting from changes in management’s estimates of undeveloped properties not expected to be developed before lease expiration. Additionally, undeveloped leasehold costs on certain properties in the Niobrara play were individually assessed for impairment in the 2013 fourth quarter based on indicators of impairment and were written down to fair value, which resulted in impairment charges being recognized of $8.4 million.
Impairment provisions for proved properties were $51.8 million for the year ended December 31, 2013 compared to $4.3 million for the same period in 2012. We evaluate proved crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then
we impair it based on an estimate of fair value based on discounted cash flows. Impairments of proved properties in 2013 primarily reflect fair value adjustments made for certain properties in the Niobrara play in Colorado and Wyoming driven by uneconomic well results. Impairment provisions for proved properties in 2012 reflect uneconomic operating results in a non-Woodford single-well field in our South region.
General and administrative expenses. General and administrative (“G&A”) expenses increased $22.7 million to $144.4 million for the year ended December 31, 2013 from $121.7 million for the comparable period in 2012. G&A expenses include non-cash charges for equity compensation of $39.9 million and $29.1 million for the years ended December 31, 2013 and 2012, respectively. The increase in equity compensation in 2013 resulted from a higher value of restricted stock grants being made throughout 2012 and 2013 due to employee growth, which resulted in increased expense recognition in 2013 compared to the prior year.
The previously announced relocation of our corporate headquarters from Enid, Oklahoma to Oklahoma City, Oklahoma was completed during 2012; however, residual costs continued to be incurred into 2013 under the terms of our relocation plan offered to employees. For the year ended December 31, 2013, we recognized approximately $1.6 million of costs in G&A expenses associated with our relocation compared to $7.8 million in 2012. Cumulative relocation costs recognized through December 31, 2013 totaled approximately $12.6 million.
G&A expenses other than equity compensation and relocation expenses increased $18.1 million, or 21%, in 2013 compared to 2012. The increase was primarily due to an increase in personnel costs and office-related expenses associated with our rapid growth. Over the past year, our Company has grown from having 753 total employees in December 2012 to 929 total employees in December 2013, a 23% increase.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented. The decrease in G&A expenses on a per-Boe basis in 2013 was due to the rapid growth in our crude oil and natural gas sales volumes coupled with an increase in G&A overhead costs billed to and recouped from our joint interest partners over the prior year, which helped generate lower costs realized per Boe.
|
| | | | | | | | |
| | | Year ended December 31, |
| $/Boe | | 2013 | | 2012 |
| General and administrative expenses | | $ | 2.07 |
| | $ | 2.38 |
|
| Non-cash equity compensation | | 0.80 |
| | 0.82 |
|
| Corporate relocation expenses | | 0.04 |
| | 0.22 |
|
| Total general and administrative expenses | | $ | 2.91 |
| | $ | 3.42 |
|
Interest expense. Interest expense increased $94.6 million to $235.3 million for the year ended December 31, 2013 from $140.7 million for the comparable period in 2012 due to an increase in our weighted average outstanding long-term debt obligations. Our weighted average outstanding long-term debt balance for the year ended December 31, 2013 was approximately $4.3 billion with a weighted average interest rate of 5.2% compared to a weighted average outstanding long-term debt balance of approximately $2.3 billion and a weighted average interest rate of 5.6% for the comparable period in 2012. The increase in outstanding debt resulted from the issuances of 5% Senior Notes due 2022 in 2012 and 4 1/2% Senior Notes due 2023 in 2013, the net proceeds of which were used to repay credit facility borrowings, to fund a portion of our capital budgets and for general corporate purposes.
Our weighted average outstanding credit facility balance decreased to $281.9 million for the year ended December 31, 2013 compared to $322.1 million for the year ended December 31, 2012. The weighted average interest rate on our credit facility borrowings was 2.0% for the year ended December 31, 2013 compared to 2.3% for the same period in 2012. At December 31, 2013, we had $275 million of outstanding borrowings on our credit facility compared to $595 million outstanding at December 31, 2012.
Income Taxes. We recorded income tax expense for the year ended December 31, 2013 of $448.8 million compared to $415.8 million for the year ended December 31, 2012, resulting in effective tax rates of approximately 37% and 36% for 2013 and 2012, respectively, after taking into account permanent taxable differences.
Year ended December 31, 2012 compared to the year ended December 31, 2011
Production
The following tables reflect our production by product and region for the periods presented.
|
| | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Volume increase | | Volume percent increase |
| | | 2012 | | 2011 | |
| | | Volume | | Percent | | Volume | | Percent | |
| Crude oil (MBbl) | | 25,070 |
| | 70 | % | | 16,469 |
| | 73 | % | | 8,601 |
| | 52 | % |
| Natural Gas (MMcf) | | 63,875 |
| | 30 | % | | 36,671 |
| | 27 | % | | 27,204 |
| | 74 | % |
| Total (MBoe) | | 35,716 |
| | 100 | % | | 22,581 |
| | 100 | % | | 13,135 |
| | 58 | % |
|
| | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Volume increase (decrease) | | Percent increase (decrease) |
| | | 2012 | | 2011 | |
| | | MBoe | | Percent | | MBoe | | Percent | |
| North Region | | 27,207 |
| | 76 | % | | 17,462 |
| | 77 | % | | 9,745 |
| | 56 | % |
| South Region | | 8,110 |
| | 23 | % | | 4,705 |
| | 21 | % | | 3,405 |
| | 72 | % |
| East Region (1) | | 399 |
| | 1 | % | | 414 |
| | 2 | % | | (15 | ) | | (4 | %) |
| Total | | 35,716 |
| | 100 | % | | 22,581 |
| | 100 | % | | 13,135 |
| | 58 | % |
| |
| (1) | In December 2012, we sold the producing crude oil and natural gas properties in our East region to a third party for $126.4 million. See Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions for further discussion of the transaction. |
Crude oil production volumes increased 52% during the year ended December 31, 2012 compared to the year ended December 31, 2011. Production increases in the Bakken field, the Northwest Cana play and SCOOP play contributed incremental production volumes in 2012 of 8,493 MBbls, an 81% increase over production in these areas for the same period in 2011. Production growth in these areas was primarily due to increased drilling and completion activity resulting from our drilling program. Additionally, production in the Red River units increased 177 MBbls, or 4%, in 2012 due to new wells being completed and enhanced recovery techniques being successfully applied.
Natural gas production volumes increased 27,204 MMcf, or 74%, during the year ended December 31, 2012 compared to the same period in 2011. Natural gas production in the Bakken field increased 9,414 MMcf, or 104%, for the year ended December 31, 2012 compared to the same period in 2011 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 Northwest Cana and SCOOP plays in Oklahoma increased 17,839 MMcf, or 156%, due to additional wells being completed and producing in the year ended December 31, 2012 compared to the same period in 2011. Further, natural gas production increased 716 MMcf, or 81%, in non-Bakken areas in the North region compared to 2011 due to the completion of new wells during the period. These increases were partially offset by a decrease in production volumes of 837 MMcf, or 6%, from non-core areas in our South region due to a combination of natural declines in production and reduced drilling activity prompted by the pricing environment for natural gas in those areas.
Revenues
Crude oil and natural gas sales. Crude oil and natural gas sales for the year ended December 31, 2012 were $2.38 billion, a 44% increase from sales of $1.65 billion for the same period in 2011. Our sales volumes increased 13,053 MBoe, or 58%, over 2011 due to the success of our drilling programs in the North Dakota Bakken field and Northwest Cana play, along with early success achieved in the emerging SCOOP play in Oklahoma. Our realized price per Boe decreased $6.22 to $66.83 for the year ended December 31, 2012 from $73.05 for the year ended December 31, 2011 due to lower commodity prices and higher crude oil differentials realized.
The differential between NYMEX WTI calendar month average crude oil prices and our realized crude oil price per barrel for the year ended December 31, 2012 was $9.06 compared to $6.39 for the year ended December 31, 2011. Overall increased production and constrained logistical factors had a negative effect on our realized crude oil prices during 2012 and resulted in higher differentials compared to 2011. Factors contributing to the changing differential included a continued increase in crude oil production across the Williston Basin from the Bakken play as well as increased production and imports from Canada.
Additionally, pipeline transportation capacity remained constrained in the Williston Basin throughout 2012 and it was not until the latter part of the year that improved rail transportation takeaway capacity began to have a positive effect on differentials. Positive effects of stronger sales pricing in coastal U.S. markets began to be realized in the fourth quarter of 2012 despite high costs being incurred for rail transportation. As a result, our crude oil differentials to NYMEX improved late in the year and averaged $3.21 per barrel for the 2012 fourth quarter.
Derivatives. Changes in commodity prices during 2012 had an overall positive net impact on the fair value of our derivatives, which resulted in net positive revenue adjustments of $154.0 million for the year. Revenues will continue to be significantly impacted, either positively or negatively, by changes in the fair value of our derivative instruments as a result of volatility in crude oil and natural gas prices. The following table presents the impact on total revenues related to cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented.
|
| | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2012 | | 2011 |
| Cash received (paid) on derivatives: | | | | |
| Crude oil derivatives | | $ | (55,579 | ) | | $ | (71,411 | ) |
| Natural gas derivatives | | 9,858 |
| | 37,305 |
|
| Cash paid on derivatives, net | | (45,721 | ) | | (34,106 | ) |
| Non-cash gain (loss) on derivatives | | | | |
| Crude oil derivatives | | 202,478 |
| | 18,753 |
|
| Natural gas derivatives | | (2,741 | ) | | (14,696 | ) |
| Non-cash gain on derivatives, net | | 199,737 |
| | 4,057 |
|
| Gain (loss) on derivative instruments, net | | $ | 154,016 |
| | $ | (30,049 | ) |
Operating Costs and Expenses
Production expenses and production taxes and other expenses. Production expenses increased 41% to $195.4 million for the year ended December 31, 2012 from $138.2 million for the year ended December 31, 2011. This increase was primarily the result of an increase in the number of producing wells. Production expense per Boe decreased to $5.49 for the year ended December 31, 2012 compared to $6.13 per Boe for the year ended December 31, 2011. This decrease was due in part to higher costs being incurred in the prior year resulting from the abnormal rainfall and flooding in North Dakota during the 2011 second quarter. The increased 2011 costs, coupled with reduced production from curtailed and shut-in wells in North Dakota during that time, resulted in higher per-unit production expenses in 2011 compared to 2012.
Production taxes and other expenses increased $83.6 million, or 58%, to $228.4 million for the year ended December 31, 2012 compared to the year ended December 31, 2011 as a result of higher crude oil and natural gas revenues resulting primarily from increased sales volumes. Production taxes and other expenses in the consolidated statements of income include other charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Oklahoma Woodford and North Dakota Bakken areas of $29.9 million and $13.7 million for the years ended December 31, 2012 and 2011, respectively. The increase in other charges is primarily due to the significant increase in natural gas sales volumes in 2012. Production taxes, excluding other charges, as a percentage of crude oil and natural gas revenues were 8.2% for the year ended December 31, 2012 compared to 7.9% for the year ended December 31, 2011. The increase was due to higher taxable revenues coming from North Dakota, our most active area, which has production tax rates of up to 11.5% of crude oil revenues.
On a unit of sales basis, production expenses and production taxes and other expenses were as follows:
|
| | | | | | | | |
| | | Year Ended December 31, |
| $/Boe | | 2012 | | 2011 |
| Production expenses | | $ | 5.49 |
| | $ | 6.13 |
|
| Production taxes and other expenses | | 6.42 |
| | 6.42 |
|
| Production expenses, production taxes and other expenses | | $ | 11.91 |
| | $ | 12.55 |
|
Exploration expenses. The following table shows the components of exploration expenses for the periods indicated.
|
| | | | | | | | |
| | | Year Ended December 31, |
| In thousands | | 2012 | | 2011 |
| Exploratory geological and geophysical costs | | $ | 22,740 |
| | $ | 19,971 |
|
| Dry hole costs | | 767 |
| | 7,949 |
|
| Exploration expenses | | $ | 23,507 |
| | $ | 27,920 |
|
Exploratory geological and geophysical costs increased $2.8 million for the year ended December 31, 2012 due to an increase in acquisitions of seismic data in connection with our increased capital budget for
2011.2012. No significant dry holes were drilled during 2012. Dry hole costs
increased $4.9 million in 2011 resulting from increased drilling activity. Dry hole costsrecognized in 2011 were
mainlyprimarily concentrated in Arkoma Woodford and Michigan.
Depreciation, Depletion, Amortizationdepletion, amortization and Accretion.accretion. Total DD&A increased $147.3$301.2 million, or 60%77%, infor the year ended December 31, 20112012 compared to the year ended December 31, 20102011 primarily due to a 43%58% increase in productionsales volumes. The following table shows the components of our DD&A on a unit of sales basis. | | | | | | | | |
| | | Year Ended December 31, | |
$/Boe | | 2011 | | | 2010 | |
Crude oil and natural gas production | | $ | 16.90 | | | $ | 14.92 | |
Other equipment | | | 0.29 | | | | 0.24 | |
Asset retirement obligation accretion | | | 0.14 | | | | 0.17 | |
| | | | | | | | |
Depreciation, depletion, amortization and accretion | | $ | 17.33 | | | $ | 15.33 | |
|
| | | | | | | | |
| | | Year Ended December 31, |
| $/Boe | | 2012 | | 2011 |
| Crude oil and natural gas properties | | $ | 19.10 |
| | $ | 16.90 |
|
| Other equipment | | 0.25 |
| | 0.29 |
|
| Asset retirement obligation accretion | | 0.09 |
| | 0.14 |
|
| Depreciation, depletion, amortization and accretion | | $ | 19.44 |
| | $ | 17.33 |
|
The increase in DD&A per Boe
iswas partially the result of a gradual shift in our production
base from our historic base of the Red River units in the Cedar Hills field to newer production bases in the Bakken and Oklahoma Woodford plays. The producing properties in our newer areas typically carry higher DD&A rates due to the higher cost of developing reserves in those areas compared to our older, more mature properties.
Property Impairments.impairments.Property impairments increased in the year ended December 31, 20112012 by $43.5$13.8 million to $108.5$122.3 million compared to $65.0$108.5 million for the year ended December 31, 2010.2011.Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually insignificant non-producing properties are amortized on an aggregate basis based on our estimated experience of successful drilling and the average holding period.
Impairments of non-producing properties increased
$29.1$25.5 million for the year ended December 31,
20112012 to
$92.4$117.9 million compared to
$63.3$92.4 million for the year ended December 31,
2010.2011. The increase resulted from a larger base of amortizable costs in
20112012 coupled with changes in management’s estimates of the undeveloped properties
no longernot expected to be developed before lease expiration.
Given current and projected prices for natural gas, we have elected to defer drilling on certain dry gas properties, thereby resulting in higher amortization of costs in 2011. We currently have no individually significant non-producing properties that would be assessed for impairment on a property-by-property basis.Impairment provisions for proved
crude oil and natural gas properties were
$16.1$4.3 million for the year ended December 31,
20112012 compared to
$1.7$16.1 million for the same period in
2010. We evaluate proved crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair value based on discounted cash flows.2011. Impairments of proved properties in
2012 primarily reflected uneconomic operating results in a non-Woodford single-well field in our South region. Impairment provisions for proved properties in 2011
primarily reflectreflected uneconomic operating results for initial wells drilled on our acreage in the Niobrara play in Colorado.
Exploration and development of the Niobrara play using multi-stage fracture stimulation technology is in the very early stages and results to date have been varied. We are seeking ways to refine and improve our geologic model and completion techniques for the play and have been encouraged by improved production being seen on our newest completions in the play. Impairments in 2010 reflect uneconomic operating results in the East region and a non-Bakken Montana field in the North region.General and Administrative Expenses.General and administrative (“expenses.G&A”)&A expenses increased $23.7$48.9 million to $72.8$121.7 million for the year ended December 31, 20112012 from $49.1$72.8 million for the comparable period in 2010.2011. G&A expenses include non-cash charges for equity compensation of $16.6$29.1 million and $11.7$16.6 million for the years ended December 31, 20112012 and 2010,2011, respectively. The increase in equity compensation in 20112012 resulted from larger grantsa higher value of restricted stock grants due to employee growth along with an increaseand new executive management personnel, which resulted in our grant-date stock prices during the year which increased expense recognition.recognition in 2012 compared to 2011. G&A expenses excludingother than equity compensation increased $18.8$36.4 million for the year ended December 31, 20112012 compared to the same period in 2010.2011. The increase was primarily relateddue in part to an increase in personnel costs and office-related expenses associated with our rapid growth. Over the past year, we have grownIn 2012, our Company grew from 493 total employees in December 2010 tohaving 609 total employees in December 2011 to 753 total employees in December 2012, a 24% increase. InAdditionally, in March 2011 we announced plans to relocate our corporate headquarters from Enid, Oklahoma to Oklahoma City, Oklahoma. The move is a key element of our growth strategy of tripling our production and proved reserves between 2009 and 2014 and is expected to beOur relocation was completed during 2012. For the year ended December 31, 2011,2012, we have recognized approximately $3.2$7.8 million of costs in G&A expenses associated with the relocation. We currently expectrelocation compared to incur a total of$3.2 million in 2011. Cumulative relocation costs recognized through December 31, 2012 totaled approximately $15 million to $25 million of costs in conjunction with the relocation, with the majority of such costs expected to be incurred in the second and third quarters of 2012.$11.0 million.
The following table shows the components of G&A expenses on a unit of sales
basis. | | | | | | | | |
| | | Year Ended December 31, | |
$/Boe | | 2011 | | | 2010 | |
General and administrative expenses | | $ | 2.36 | | | $ | 2.35 | |
Non-cash equity compensation | | | 0.73 | | | | 0.74 | |
Corporate relocation expenses | | | 0.14 | | | | — | |
| | | | | | | | |
General and administrative expenses | | $ | 3.23 | | | $ | 3.09 | |
basis for the periods presented.
|
| | | | | | | | |
| | Year Ended December 31, |
| $/Boe | | 2012 | | 2011 |
| General and administrative expenses | | $ | 2.38 |
| | $ | 2.36 |
|
| Non-cash equity compensation | | 0.82 |
| | 0.73 |
|
| Corporate relocation expenses | | 0.22 |
| | 0.14 |
|
| Total general and administrative expenses | | $ | 3.42 |
| | $ | 3.23 |
|
Interest Expense. Interest expense increased $23.6$64.0 million or 44%,to $140.7 million for the year ended December 31, 2011 compared to2012 from $76.7 million for the samecomparable period in 20102011 due to increasesan increase in our weighted average outstanding long-term debt balance and our weighted average interest rate.obligations. Our weighted average interest rateoutstanding long-term debt balance for the year ended December 31, 20112012 was 7.2%approximately $2.3 billion with a weighted average interest rate of 5.6% compared to a weighted average outstanding long-term debt balance of approximately $970.0 million compared toand a weighted average interest rate of 7.0% with a weighted average outstanding long-term debt balance of $685.8 million7.2% for the samecomparable period in 2010. We2011. The increase in outstanding debt resulted from borrowings incurred to fund increased amounts of capital expenditures and property acquisitions in 2012 compared to 2011. On March 8, 2012 and August 16, 2012, we issued $200$800 million and $1.2 billion, respectively, of 7 3/8%5% Senior Notes in April 2010due 2022 and $400 million of 7 1/8% Senior Notes in September 2010,used the net proceeds of which were usedfrom those issuances to repay credit facility borrowings, that carried lower interest rates.to fund a portion of our 2012 capital budget and for general corporate purposes. Our weighted average outstanding credit facility balance
decreasedincreased to $322.1 million for the year ended December 31, 2012 compared to $70.0 million for the year ended December 31,
2011 compared to $121.7 million for the year ended December 31, 2010.2011. The weighted average interest rate on our credit facility borrowings was
2.4%2.3% for the year ended December 31,
20112012 compared to
2.7%2.4% for the same period in
2010.2011. At December 31,
2011,2012, we had
$358.0$595 million of outstanding borrowings on our credit facility
compared to $358.0 million outstanding at
a weighted average interest rate of 2.0%.December 31, 2011. The increase in credit facility borrowings in 2012 was driven by the aforementioned increase in capital expenditures and property acquisitions during the year.
Income Taxes. We recorded income tax expense for the year ended December 31, 20112012 of $258.4$415.8 million compared to $90.2$258.4 million for the year ended December 31, 2010. We provide for income taxes at a combined federal and state2011, resulting in effective tax raterates of approximately 36% and 38% for 2012 and 2011, respectively, after taking into account permanent taxable differences. SeeNotes to Consolidated Financial Statements—Note 8. Income Taxes for more information.Year ended December 31, 2010 compared to the year ended December 31, 2009
Production
The following tables reflect our production by product and region for the periods presented.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | Volume
increase | | | Percent
increase | |
| | | 2010 | | | 2009 | | | |
| | | Volume | | | Percent | | | Volume | | | Percent | | | |
Crude oil (MBbl) | | | 11,820 | | | | 75 | % | | | 10,022 | | | | 74 | % | | | 1,798 | | | | 18 | % |
Natural gas (MMcf) | | | 23,943 | | | | 25 | % | | | 21,606 | | | | 26 | % | | | 2,337 | | | | 11 | % |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total (MBoe) | | | 15,811 | | | | 100 | % | | | 13,623 | | | | 100 | % | | | 2,188 | | | | 16 | % |
| | | |
| | | Year Ended December 31, | | | Volume
increase
(decrease) | | | Percent
increase
(decrease) | |
| | | 2010 | | | 2009 | | | |
| | | MBoe | | | Percent | | | MBoe | | | Percent | | | |
North | | | 12,431 | | | | 79 | % | | | 10,314 | | | | 76 | % | | | 2,117 | | | | 21 | % |
South | | | 2,915 | | | | 18 | % | | | 2,784 | | | | 20 | % | | | 131 | | | | 5 | % |
East | | | 465 | | | | 3 | % | | | 525 | | | | 4 | % | | | (60 | ) | | | (11 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total (MBoe) | | | 15,811 | | | | 100 | % | | | 13,623 | | | | 100 | % | | | 2,188 | | | | 16 | % |
Crude oil production volumes increased 18% during the year ended December 31, 2010 compared to the year ended December 31, 2009. Production increases in the North Dakota Bakken field, Red River units, and the Oklahoma Woodford play contributed incremental production volumes in 2010 of 2,262 MBbls in excess of production for the same period in 2009. Favorable drilling results were the primary contributors to production growth in these areas. Natural gas production volumes increased 2,337 MMcf, or 11%, during the year ended December 31, 2010 compared to the same period in 2009. Natural gas production in the Bakken field in the North region was up 2,172 MMcf compared to the same period in 2009 due to additional natural gas being connected and sold in North Dakota. Natural gas production in the Oklahoma Woodford area increased 1,471 MMcf due to additional wells being completed and producing during the year ended December 31, 2010 compared to 2009. The increased natural gas production in the Bakken and Oklahoma Woodford plays was partially offset by decreases in natural gas volumes of 916 MMcf in the Cedar Hills field due to the conversion of producing wells to injection wells and 801 MMcf due to natural declines in non-Woodford areas in the South region.
Revenues
Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the year ended December 31, 2010 were $948.5 million, a 55% increase from sales of $610.7 million for 2009. Our realized price per Boe increased $14.60 to $59.70 for the year ended December 31, 2010 from $45.10 for the year ended December 31, 2009. Our sales volumes increased 2,348 MBoe, or 17%, over the same period in 2009 due to the continuing success of our drilling programs in the Bakken field and additional natural gas being connected and sold in the North region. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the year ended December 31, 2010 was $9.02 compared to $8.29 for 2009. Factors contributing to the changing differentials included Canadian crude oil imports and increases in production in the North region, coupled with downstream transportation capacity constraints and demand fluctuations.
Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value on derivative instruments in the consolidated income statements under the caption “Loss on derivative instruments, net.”
During the year ended December 31, 2010, we realized gains on natural gas derivatives of $22.3 million and realized gains on crude oil derivatives of $13.2 million. During the year ended December 31, 2010, we reported an unrealized non-cash mark-to-market gain on natural gas derivatives of $19.8 million and an unrealized non-cash mark-to-market loss on crude oil derivatives of $186.0 million. During the year ended December 31, 2009, we realized gains on natural gas derivatives of $0.6 million and reported an unrealized non-cash mark-to-market gain on natural gas derivatives of $1.6 million and an unrealized non-cash mark-to-market loss on crude oil derivatives of $3.7 million.
Crude Oil and Natural Gas Service Operations. Our crude oil and natural gas service operations consist primarily of the treatment and sale of lower quality crude oil, or reclaimed crude oil. The table below shows the volumes and prices for the sale of reclaimed crude oil for the periods presented.
| | | | | | | | | | | | |
| | | Year ended December 31, | | | Variance | |
Reclaimed crude oil sales | | 2010 | | | 2009 | | |
Average sales price ($/Bbl) | | $ | 69.35 | | | $ | 48.57 | | | $ | 20.78 | |
Sales volumes (barrels) | | | 227,000 | | | | 199,000 | | | | 28,000 | |
During the year ended December 31, 2010, the average sales price for reclaimed crude oil sold from our central treating units was $20.78 per barrel higher than the comparable 2009 period, which contributed to an increase in reclaimed crude oil revenue of $5.8 million to $16.8 million, contributing to an overall increase in crude oil and natural gas service operations revenue of $4.3 million for the year ended December 31, 2010. During the year ended December 31, 2009, we sold high-pressure air from our Red River units to a third party and recorded revenues of $2.2 million. Beginning January 2010, we no longer sell high-pressure air to a third party. Associated crude oil and natural gas service operations expenses increased $7.3 million to $18.1 million during the year ended December 31, 2010 compared to the same period in 2009 due mainly to an increase in the costs of purchasing and treating reclaimed crude oil for resale.
Operating Costs and Expenses
Production Expenses, Production Taxes and Other Expenses. Production expense remained consistent at $93.2 million during the years ended December 31, 2010 and 2009. Production expense per Boe decreased to $5.87 for the year ended December 31, 2010 from $6.89 per Boe for the year ended December 31, 2009. In 2009, we leased compressors from a related party for approximately $400,000 per month under an operating lease and a new agreement was negotiated effective February 1, 2010 through November 2010 resulting in the monthly lease fee being reduced to $50,000, lowering production expense per Boe for the 2010 period. The per unit decrease was also driven by longer natural production periods on certain North Dakota Bakken wells that resulted in lower
artificial lifting costs, positive secondary recovery efforts in the Cedar Hills field that have resulted in lower-cost improvements in production, and the conversion of certain high pressure air injection units to less costly waterflood units during 2010, which also contributed to lower-cost improvements in production.
Production taxes and other expenses increased $31.0 million, or 68%, during the year ended December 31, 2010 compared to the year ended December 31, 2009 as a result of higher revenues resulting from increased commodity prices and sales volumes along with the expiration of various tax incentives. Production taxes and other expenses include charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Arkoma Woodford area of $6.1 million and $6.8 million for the years ended December 31, 2010 and 2009, respectively. Production taxes, excluding other expenses, as a percentage of crude oil and natural gas sales were 7.5% for the year ended December 31, 2010 compared to 6.5% for the year ended December 31, 2009. The increase is due to the expiration of various tax incentives coupled with higher taxable revenues in North Dakota, our most active area, which has production tax rates of up to 11.5% of crude oil revenues. Production taxes are based on the wellhead values of production and vary by state. Additionally, some states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of crude oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana and Oklahoma, new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate reverts to the statutory rate. Our overall production tax rate is expected to increase as production tax incentives we currently receive for horizontal wells reach the end of their incentive periods.
On a unit of sales basis, production expenses and production taxes and other expenses were as follows:
| | | | | | | | |
| | | Year Ended December 31, | |
$/Boe | | 2010 | | | 2009 | |
Production expenses | | $ | 5.87 | | | $ | 6.89 | |
Production taxes and other expenses | | | 4.82 | | | | 3.37 | |
| | | | | | | | |
Production expenses, production taxes and other expenses | | $ | 10.69 | | | $ | 10.26 | |
Exploration Expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses increased $0.1 million in the year ended December 31, 2010 to $12.8 million due primarily to an increase in seismic expense of $3.8 million to $5.8 million offset by a decrease in dry hole expense of $3.5 million to $3.0 million. The majority of the dry hole costs, 76%, were in the South region for the year ended December 31, 2010 and 67% of the dry hole costs for the 2009 period were in the East region.
Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $36.0 million, or 17%, in the year ended December 31, 2010 compared to the same period in 2009, primarily due to an increase in production volumes. The following table shows the components of our DD&A rate per Boe.
| | | | | | | | |
| | | Year Ended December 31, | |
$/Boe | | 2010 | | | 2009 | |
Crude oil and natural gas production | | $ | 14.92 | | | $ | 14.94 | |
Other equipment | | | 0.24 | | | | 0.23 | |
Asset retirement obligation accretion | | | 0.17 | | | | 0.17 | |
| | | | | | | | |
Depreciation, depletion, amortization and accretion | | $ | 15.33 | | | $ | 15.34 | |
Property Impairments. Property impairments, proved and non-producing, decreased in the year ended December 31, 2010 by $18.7 million to $65.0 million compared to $83.7 million during the year ended December 31, 2009.
Impairment of non-producing properties increased $16.2 million during the year ended December 31, 2010 to $63.3 million compared to $47.1 million for 2009 reflecting higher amortization of leasehold costs resulting from a larger base of amortizable costs. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Non-producing properties are amortized on a composite method based on our estimated experience of successful drilling and the average holding period.
Impairment provisions for proved crude oil and natural gas properties were approximately $1.7 million for the year ended December 31, 2010 compared to approximately $36.6 million for the year ended December 31, 2009, a decrease of $34.9 million, or 95%. We evaluate our proved crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair value based on discounted cash flows. Impairments of proved properties in 2010 reflect uneconomic operating results in the East region and a non-Bakken field in the North region. Impairments of proved properties in 2009 were primarily related to uneconomic wells in our South region and a non-Bakken field in the North region.
General and Administrative Expenses. General and administrative expenses increased $8.0 million to $49.1 million during the year ended December 31, 2010 from $41.1 million during the comparable period of 2009. General and administrative expenses include non-cash charges for stock-based compensation of $11.7 million and $11.4 million for the years ended December 31, 2010 and 2009, respectively. General and administrative expenses, excluding equity compensation, increased $7.7 million for the year ended December 31, 2010 compared to the year ended December 31, 2009. The increase was primarily related to an increase in personnel costs and office related expenses associated with our growth during the year. On a volumetric basis, general and administrative expenses increased $0.06 to $3.09 per Boe for the year ended December 31, 2010 compared to $3.03 per Boe for the year ended December 31, 2009.
Interest Expense. Interest expense increased $29.9 million, or 129%, for the year ended December 31, 2010 compared to the year ended December 31, 2009 due to an increase in our outstanding debt balance and higher rates of interest on our senior notes in 2010 as compared to lower interest rates on our credit facility borrowings in 2009. On September 23, 2009, we issued $300 million of 8 1/4% Senior Notes due 2019. On April 5, 2010, we issued $200 million of 7 3/8% Senior Notes due 2020. On September 16, 2010, we issued $400 million of 7 1/8% Senior Notes due 2021. We recorded $45.4 million in interest expense on the outstanding senior notes for the year ended December 31, 2010. Including the interest on the senior notes, our weighted average interest rate for the year ended December 31, 2010 was 7.0% with a weighted average outstanding long-term debt balance of $685.8 million compared to a weighted average interest rate of 3.8% and a weighted average outstanding long-term debt balance of $507.7 million for the year ended December 31, 2009.
Our weighted average outstanding revolving credit facility balance decreased to $121.7 million for the year ended December 31, 2010 compared to $426.3 million for the year ended December 31, 2009. The weighted average interest rate on our revolving credit facility borrowings was lower at 2.7% for the year ended December 31, 2010 compared to 2.9% for the same period in 2009. At December 31, 2010, we had $30.0 million of outstanding borrowings on our revolving credit facility.
Income Taxes. Income taxes for the year ended December 31, 2010 were $90.2 million compared to $38.7 million for the year ended December 31, 2009. We provided for income taxes at a combined federal and state tax rate of approximately 35% for both 2010 and 2009 after taking into account permanent taxable differences. SeeNotes to Consolidated Financial Statements—Note 8. Income Taxes for more information.
Liquidity and Capital Resources
Our primary sources of liquidity have been cash flows generated from operating activities, financing provided by our revolving credit facility and the issuance of debt and equity securities. During the year ended December 31, 2011, our average realized sales price was $13.35 per Boe higher compared to the year ended December 31, 2010. The increase in realized commodity prices, coupled with our 42% increase in sales volumes in 2011 compared to 2010, resulted in improved cash flows from operations and better liquidity.At December 31, 2011,2013, we had $53.5$28.5 million of cash and cash equivalents and $389.2 million
$1.2 billion of available capacity underborrowing availability on our revolving credit facility after considering outstanding borrowings and letters of credit. Subsequent toWe had $275 million of outstanding borrowings on our credit facility at December 31, 2011, we requested, and were granted by the lenders, an increase in our credit facility’s aggregate commitments from $750 million to $1.25 billion, effective January 31, 2012. At 2013. As of February 15, 2012,17, 2014, we had $347.2$560 million of outstanding borrowings and approximately $936 million of borrowing availability on our credit facility after considering the increased commitments and outstanding borrowings and letters of credit. The decrease in borrowing availability subsequent to December 31, 2011 resulted Cash Flows
Cash flows from
borrowings incurred to fund our 2012 capital program and a February 2012 acquisition of producing and non-producing properties in North Dakota for $276 million.Cash Flows
Cash Flows from Operating Activities
operating activities
Our net cash provided by operating activities was
$1,067.9 million$2.6 billion and
$653.2 million$1.6 billion for the years ended December 31,
20112013 and
2010,2012, respectively. The increase in operating cash flows was primarily due to higher crude oil and natural gas revenues
as a result ofdriven by higher
sales volumes and higher realized commodity prices,
and sales volumes,which were partially offset by an increase in
realizedcash 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
in 2011.during the year.
Cash
Flowsflows used in
Investing Activitiesinvesting activities
During the years ended December 31, 20112013 and 2010,2012, we had cash flows used in investing activities (excluding proceeds from asset sales)sales and other) of $2,035.6 million$3.74 billion and $1,083.4 million,$4.12 billion, respectively, related to our capital program, inclusive of dry hole costs. Thecosts and property acquisitions. Cash acquisition capital expenditures totaled $268.1 million and $1.1 billion for the years ended December 31, 2013 and 2012, respectively. In 2012 we executed certain transactions to acquire properties in North Dakota totaling $939 million, with no transactions of similar size in 2013. Cash capital expenditures excluding acquisitions totaled $3.47 billion and $2.99 billion for the years ended December 31, 2013 and 2012, respectively, the increase of which was driven by an increase in our capital budget for 2013.
The use of cash for capital expenditures during the year ended December 31, 2012 was partially offset by proceeds received from asset dispositions. Proceeds from the sale of assets amounted to $214.7 million for 2012, primarily related to our February 2012 disposition of certain Wyoming properties for proceeds of $84.4 million, our June 2012 disposition of certain Oklahoma properties for proceeds of $15.9 million, and our December 2012 disposition of certain East region properties for $126.4 million, of which $14.0 million had not been received at December 31, 2012. No significant asset dispositions occurred during the year ended December 31, 2013.
Cash flows
used in investingfrom financing activities
in 2011 was primarily due to the continued acceleration of our drilling program, primarily in the North Dakota Bakken field and the Anadarko Woodford play in Oklahoma.Cash Flows from Financing Activities
Net cash provided by financing activities for the year ended December 31, 2011 was $982.42013 totaled $1.1 billion, primarily resulting from the receipt of $1.48 billion of net proceeds from the issuance of $1.5 billion of 4 1/2% Senior Notes due 2023 in April 2013, partially offset by net repayments of $320.0 million andon our credit facility during the year.
Net cash provided by financing activities of $2.3 billion for the year ended December 31, 2012 was primarily the result of
$787.0 million of net proceeds received from the March 2012 issuance of $800 million of 5% Senior Notes due 2022 and an additional $1.21 billion of net proceeds received from the issuance
and sale of
an aggregate 10,080,000 shares$1.2 billion of
our common stockadditional 2022 Notes at 102.375% of par in
March 2011 for total net proceedsAugust 2012, along with $237.0 million of
$659.4 million, after deducting underwriting discounts and offering-related expenses, coupled with net borrowings
of $328 millionmade on our credit facility to fund a portion of our
20112012 capital program.
Net cash provided by financing activities of $379.9 million for the year ended December 31, 2010 was mainly the result of receiving $587.2 million of net proceeds from the issuance of the 2020 Notes in April 2010 and the 2021 Notes in September 2010, reduced by net repayments of $196 million on our credit facility and $9.1 million of costs incurred in connection with our senior note issuances. Future Sources of Financing
Although we cannot provide any assurance, assuming
continuedsustained 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
revolving 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,
budgetedplanned capital expenditures, and commitments
and contingencies 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
revolving 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 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.
Revolving
We have a
revolving credit facility,
which hadmaturing on July 1, 2015, that has aggregate lender commitments totaling
$750.0 million and a borrowing base of $2.25 billion at December 31, 2011, subject to semi-annual redetermination. The most recent borrowing base redetermination was completed in October 2011, whereby the lenders approved$1.5 billion. In November 2013, following an
increase in the borrowing base from $2.0 billion to $2.25 billion. Subsequent to December 31, 2011, we requested, and were grantedupgrade by
the lenders, an increase in the aggregate credit facility commitments from $750 million to $1.25 billion, effective January 31, 2012. Our borrowing base of $2.25 billion and all other substantive terms ofS&P, as permitted by the credit facility
remained unchanged. The increased commitment level will provide additional available liquidity if needed to maintain our growth strategy, take advantage of business opportunities, and fund our capital program. The aggregate commitment level may be further increased at our option from time to time (provided no default exists) up toterms, we provided the
lesser of $2.5 billion or the borrowing base then in effect. Borrowings under the facility bear interest, payable quarterly, at a rate per annum equal to the London Interbank Offered Rate (LIBOR) for one, two, three or six months, as elected by us, plus a margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized, or the lead bank’s reference rate (prime) plus a margin ranging from 75 to 175 basis points.The commitmentslenders under our credit facility which matures on July 1, 2015,notice of our intention to elect an Additional Covenant Period. The election of an Additional Covenant Period means that the credit facility is not currently subject to a borrowing base. The election was made in order to facilitate the release of collateral consisting of oil and gas properties securing obligations under the credit facility. On December 11, 2013, we delivered notice to the credit facility lenders confirming we had satisfied all conditions for releasing the collateral and the release of such collateral became effective as of December 12, 2013. On December 13, 2013, our credit rating was upgraded by Moody's. As a result of the second upgrade, we are not currently required to: (i) comply with certain reporting requirements; and (ii) maintain a ratio of the present value of oil and gas properties to total funded debt of not less than 1.5 to 1.0, as set forth in the credit facility.
The credit facility's commitments of $1.5 billion can be increased up to $2.5 billion under the terms of the facility. The commitments are from a syndicate of
1513 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. If one or more lenders cannot fund its commitment, we
wouldmay not have the full availability of the
$1.25$1.5 billion commitment.
We had $358.0$275 million of outstanding borrowings and $389.2 million$1.2 billion of borrowing availability (after considering outstanding borrowings and letters of credit) on our credit facility as ofat December 31, 2011.2013. As of February 15, 2012,17, 2014, we had $900.0$560 million of outstanding borrowings and $347.2$936 million of borrowing availability on our credit facility after(after considering the increased commitmentsoutstanding borrowings and outstanding letters of credit.credit). The increase in outstanding borrowings subsequent to December 31, 20112013 resulted from borrowings incurred to fund a portion of our 20122014 capital program and a February 2012 acquisition of producing and non-producing properties in North Dakota for $276 million.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 agreementfacility 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 3.754.0 to 1.0. As defined by our credit agreement, the current ratio represents our ratio of current assets to current liabilities, inclusive of available borrowing capacity under the credit agreement 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, unrealized derivative gains and losses and non-cash equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. A reconciliation of net income to EBITDAX is provided subsequently under the captionNon-GAAP Financial Measures. The total funded debt to EBITDAX ratio represents the sum of outstanding borrowings and letters of credit under our revolving credit facility plus our senior note obligations, divided by total EBITDAX for the most recent four quarters. We were in compliance with these covenants at December 31, 20112013 and expect to maintain compliance for at least the next 12 months. At December 31, 2011,2013, our current ratio, as defined, was 1.31.7 to 1.0 and our total funded debt to EBITDAX ratio was 1.01.7 to 1.0. A violation of these covenants in the future could result in a default under our credit facility and such event could result in an acceleration of other outstanding indebtedness. In the event of such default, the lenders under our credit facility could elect to terminate their commitments thereunder, cease making further loans, and could declare all outstanding amounts, if any, to be due and payable. If outstanding borrowings under our credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness. 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. Our ability to remain in an Additional Covenant Period as described above is dependent on the credit ratings assigned to our senior unsecured debt. 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 nullifies our eligibility for the Additional Covenant Period and triggers the reinstatement of a borrowing base
duerequirement, subjecting us to the
outcomerisk that other events may adversely impact the size of
a subsequentour borrowing base,
redetermination,(ii) a decline in commodity prices, or
(ii)(iii) an unwillingness or inability on the part of our lending counterparties to meet their funding
obligations. We expectobligations or increase their commitments as required under the
next borrowing base redetermination to occur in the second quarter of 2012. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base.credit facility.
If we are unable to access funding
when needed 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.
Derivative
Activitiesactivities
As part of our risk management program, we economically hedge a portion of our anticipated future crude oil and natural gas production to achieve more predictable cash flows and to reduce our exposure to fluctuations in crude oil and natural gas prices. Reducing our exposure to price volatility helps ensure adequate funds are available for our capital program. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions and our desire to have the cash flows needed to fund the development of our inventory of undeveloped crude oil and natural gas reserves in conjunction with our growth strategy. While the use of hedging arrangements limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.See
Our hedging transactions existing at December 31, 2011 are settled based upon reported settlement prices on the NYMEX, with our crude oil derivatives being tied to West Texas Intermediate (“WTI”) pricing and our natural gas derivatives being tied to Henry Hub pricing. A significant portion of our operated crude oil production in the North region is being sold in markets other than Cushing, Oklahoma and is priced, apart from transportation costs, at a premium to the WTI benchmark pricing in that market center. As such, WTI has become an unreliable reflection of the realized value of our North region crude oil production. Historically, WTI and Inter-Continental Exchange pricing for Brent crude oil have fluctuated together, but in 2011 the two indices began to diverge. At this time, we believe the current pricing for Brent crude oil is more reflective of the sales prices currently being realized for our North region production. Accordingly, for recent crude oil derivative contracts entered into subsequent to December 31, 2011, we decided to base such contracts on Brent pricing. While this approach is consistent with our current viewpoint, such viewpoint could change based on future fluctuations in WTI and Brent prices and the correlation of such prices to our realized prices. Therefore, our future hedging program may include contracts based on WTI prices, Brent prices, or a combination of both. A summary of Brent-based crude oil derivatives entered into after December 31, 2011 is provided subsequently under the headingCrude Oil and Natural Gas Hedging. Also refer toNote 5. Derivative Instruments inNotes to Consolidated Financial Statements for further discussion of the accounting applicable to our derivative instruments, a summary of open contracts at December 31, 20112013 and the estimated fair value of those contracts as of that date. Additionally, a summary of derivative contracts entered into after December 31, 2013 is provided subsequently under the heading Crude Oil and Natural Gas Hedging. We have hedgedexpect to continue entering into derivative instruments covering a significant portion of our forecastedfuture crude oil and/or natural gas production throughin order to further secure cash flows in support of our growth plans; however, we may choose not to hedge future production if the pricing environment for certain time periods is not deemed to be favorable. Future Capital Requirements
Senior notes
Our long-term debt includes outstanding senior note obligations totaling $4.4 billion at December 31, 2013. 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 a discussion offurther information on the potential risks associatedmaturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, see Part II, Item 8. Notes to Consolidated Financial Statements - Note 7. Long-Term Debt. We were in compliance with our hedging program, refersenior note covenants at December 31, 2013 and expect toPart I, Item 1A. Risk Factors— 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
derivative activities could result in financial losses or reduce our earnings.Future other subsidiary, 20 Broadway Associates LLC, the value of whose assets and operations are minor, does not guarantee the senior notes.
Capital
RequirementsCapital Expenditures
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.
During
For the year ended December 31,
2011,2013, we
participated in the completion of 563 gross (198.9 net) wells and invested
$2,046.1 millionapproximately $3.57 billion in our capital program,
(including increases in accruals for capital expendituresexcluding $268.1 million of
$173.6 millionunbudgeted acquisitions and
$14.9including $28.4 million of seismic costs and
excluding unbudgeted property acquisitions). During 2011, we invested $178$89.5 million
in unbudgeted leasehold and producing property acquisitions, resulting in totalof capital costs associated with increased accruals for capital expenditures. Our capital expenditures
of $2,224.1 millionbudget for
the year. Our 20112013 was $3.60 billion, excluding acquisitions which are not budgeted. 2013 capital expenditures were allocated as follows:
| | | | |
| | | Amount | |
| | | in millions | |
Exploration and development drilling | | $ | 1,774.3 | |
Land costs | | | 273.6 | |
Capital facilities, workovers and re-completions | | | 51.3 | |
Buildings, vehicles, computers and other equipment | | | 44.7 | |
Acquisitions of producing properties | | | 65.3 | |
Seismic | | | 14.9 | |
| | | | |
Total | | $ | 2,224.1 | |
|
| | | |
| In millions | Amount |
| Exploration and development drilling | $ | 3,120.9 |
|
| Land costs | 295.4 |
|
| Capital facilities, workovers and re-completions | 66.9 |
|
| Buildings, vehicles, computers and other equipment | 61.9 |
|
| Seismic (1) | 28.4 |
|
| Capital expenditures, excluding acquisitions | $ | 3,573.5 |
|
| Acquisitions of producing properties | 16.6 |
|
| Acquisitions of non-producing properties | 251.5 |
|
| Total acquisitions | 268.1 |
|
| Total capital expenditures | $ | 3,841.6 |
|
| |
| (1) | Includes $12.9 million of exploratory seismic costs recognized as exploration expense and $15.5 million of developmental seismic costs capitalized in conjunction with development drilling projects. |
Our
20112013 capital program focused primarily on increased
exploration and development in the
Bakken field of North Dakota
Bakken fieldand Montana and the
Anadarko WoodfordSCOOP play in
westernsouth-central Oklahoma.
In November 2011,September 2013, our Board of Directors approved a 20122014 capital expendituresexpenditure budget of $1.75 billion. Our 2012 planned capital expenditures are$4.05 billion excluding acquisitions, which is expected to be allocated as follows: | | | | |
| | Amount | |
| | in millions | |
Exploration and development drilling
| | $ | 1,539 | |
Land costs
| | | 94 | |
Capital facilities, workovers and re-completions
| | | 90 | |
Buildings, vehicles, computers and other equipment
| | | 7 | |
Seismic
| | | 20 | |
| | | | |
Total
| | $ | 1,750 | |
The 2012
|
| | | |
| In millions | Amount |
| Exploration and development drilling | $ | 3,540 |
|
| Land costs | 300 |
|
| Capital facilities, workovers and re-completions | 150 |
|
| Buildings, vehicles, computers and other equipment | 30 |
|
| Seismic | 30 |
|
| Total 2014 capital budget, excluding acquisitions | $ | 4,050 |
|
Our 2014 capital plan
will focus primarilyis expected to continue focusing on
increasedexploratory and development
drilling in the
North Dakota Bakken field and
Anadarko Woodfordthe SCOOP play.
During 2012, we expect to participate as a buyer of properties when and if we have the ability to increase our position in strategic plays at favorable terms. In February 2012, we acquired certain producing and non-producing properties in North Dakota for approximately $276 million. This transaction is not included in our 2012 capital budget reflected in the table above. Although we cannot provide any assurance, assuming
continuedsustained strength in crude oil prices and successful implementation of our business strategy, including the future development of our proved reserves and realization of our cash flows as anticipated, we believe funds from operating cash flows, our remaining cash balance, and our
revolving credit facility,
including our ability to increase our borrowing capacity thereunder, will be sufficient to fund our
2012planned 2014 capital
budget.program; however, we may choose to access the capital markets for additional financing to take advantage of business opportunities that may arise if such financing can be arranged at favorable terms. The actual amount and timing of our capital expenditures may differ materially from our estimates as a result of, among other things, 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.
Contractual Obligations
Further, 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.
Contractual Obligations
The following
table presents our contractual obligations and commitments as of December 31,
2011: | | | | | | | | | | | | | | | | | | | | |
| | | Payments due by period | |
(in thousands) | | Total | | | Less than
1 year (2012) | | | 1 - 3
years
(2013-2014) | | | 3 - 5
years
(2015-2016) | | | More than
5 years | |
Arising from arrangements on the balance sheet: | | | | | | | | | | | | | | | | | | | | |
Revolving credit facility | | $ | 358,000 | | | $ | — | | | $ | — | | | $ | 358,000 | | | $ | — | |
Senior Notes (1) | | | 900,000 | | | | — | | | | — | | | | — | | | | 900,000 | |
Interest expense (2) | | | 610,695 | | | | 75,545 | | | | 150,678 | | | | 139,846 | | | | 244,626 | |
Asset retirement obligations (3) | | | 62,625 | | | | 2,287 | | | | 10,453 | | | | 2,055 | | | | 47,830 | |
Arising from arrangements not on balance sheet: | | | | | | | | | | | | | | | | | | | | |
Operating leases (4) | | | 5,901 | | | | 2,191 | | | | 3,340 | | | | 176 | | | | 194 | |
Drilling rig commitments (5) | | | 136,516 | | | | 117,649 | | | | 18,867 | | | | — | | | | — | |
Fracturing and well stimulation services (6) | | | 43,738 | | | | 27,050 | | | | 16,688 | | | | — | | | | — | |
Firm transportation commitment (7) | | | 30,988 | | | | 6,771 | | | | 13,505 | | | | 10,712 | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Total contractual obligations | | $ | 2,148,463 | | | $ | 231,493 | | | $ | 213,531 | | | $ | 510,789 | | | $ | 1,192,650 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Payments due by period |
| In thousands | | Total | | Less than
1 year (2014) | | Years 2 and 3
(2015-2016) | | Years 4 and 5
(2017-2018) | | More than
5 years |
| Arising from arrangements on the balance sheet: | |
| |
| |
| |
| |
|
| Credit facility borrowings | | $ | 275,000 |
| | $ | — |
| | $ | 275,000 |
| | $ | — |
| | $ | — |
|
| Senior Notes (1) | | 4,400,000 |
| | — |
| | — |
| | — |
| | 4,400,000 |
|
| Note payable (2) | | 18,470 |
| | 2,011 |
| | 4,222 |
| | 4,500 |
| | 7,737 |
|
| Interest expense (3) | | 1,956,796 |
| | 240,701 |
| | 474,857 |
| | 471,643 |
| | 769,595 |
|
| Asset retirement obligations (4) | | 55,787 |
| | 1,434 |
| | 1,209 |
| | 176 |
| | 52,968 |
|
| Arising from arrangements not on balance sheet: | |
| |
| |
| |
| |
|
| Operating leases and other (5) | | 7,027 |
| | 3,811 |
| | 2,628 |
| | 406 |
| | 182 |
|
| Drilling rig commitments (6) | | 109,510 |
| | 83,336 |
| | 26,174 |
| | — |
| | — |
|
| Fracturing and well stimulation services (7) | | 15,853 |
| | 15,853 |
| | — |
| | — |
| | — |
|
| Pipeline transportation commitments (8) | | 67,290 |
| | 16,188 |
| | 28,992 |
| | 10,010 |
| | 12,100 |
|
| Rail transportation commitments (9) | | 9,821 |
| | 9,821 |
| | — |
| | — |
| | — |
|
| Cost sharing commitment (10) | | 24,538 |
| | 14,925 |
| | 9,613 |
| | — |
| | — |
|
| Total contractual obligations | | $ | 6,940,092 |
| | $ | 388,080 |
| | $ | 822,695 |
| | $ | 486,735 |
| | $ | 5,242,582 |
|
| |
| (1) | Amounts represent scheduled maturities of our debtsenior note obligations at December 31, 20112013 and do not reflect the discountsany discount or premium at which the Senior Notessenior notes were issued. SeeNotes to Consolidated Financial Statements—Note 7. Long-Term Debt for a description of our Senior Notes.senior notes. |
| |
| (2) | Represents future principal payments on $22 million borrowed in February 2012 under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. |
| |
| (3) | Interest expense includes scheduled cash interest payments on the senior notes and note payable as well as estimated interest payments on our credit facility borrowings outstanding at December 31, 20112013 and assumes the actual weighted average interest rate on our credit facility borrowings of 2.0%1.7% at December 31, 20112013 continues forthrough the lifeJuly 1, 2015 maturity date of the credit facility. |
(3) | |
| (4) | Amounts represent estimated discounted costs for future dismantlement and abandonment of our crude oil and natural gas properties. See Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies for additional discussion of our asset retirement obligations. |
(4) | Operating lease obligations |
| (5) | Amounts primarily represent leases for office space, office equipment, communication towers and tanks for storage of hydraulic fracturing tank rentals. SeeNotesfluids, in addition to Consolidated Financial Statements—Note 9. Lease Commitments.purchase obligations mainly related to software services. |
(5) | We have |
| (6) | Amounts represent commitments under drilling rig contracts with various terms extending through August 2014.January 2016. These contracts were entered into in the normalordinary course of business to ensure rig availability to allow us to execute our business objectives in our key strategic plays. These drilling commitments are not recorded in the accompanying consolidated balance sheets. |
(6) | |
| (7) | We have an agreement with a third party whereby the third party will provide, on a take-or-pay basis, hydraulic fracturing services and related equipment to service certain of our properties in North Dakota and Montana. The arrangement has a term of three years, beginningagreement, which expires in October 2010, with two one-year extensions availableSeptember 2014, requires us to us at our discretion. Pursuant to the take-or-pay provisions, we will pay a fixed rate per day for a minimum number of days per calendar quarter over the three-year term regardless of whether the services are provided. Future commitments remaining as of December 31, 2011 amount to approximately $39 million, of which $22 million is expected to be incurred in 2012 and $17 million in 2013. Additionally, we have an agreement whereby a third party will provide coiled tubing well stimulation services for certain of our properties in Oklahoma at a fixed rate per month for calendar year 2012, resulting in total future commitments of approximately $5 million as of December 31, 2011. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets. |
(7) | |
| (8) | We have a five-yearentered into firm transportation commitment, beginningcommitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines in August 2011,order to move our production to market and to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. These commitments require us to pay per-unit transportation charges regardless of the amount of pipeline capacity used. We are not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. See Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies for additional discussion. |
| |
| (9) | We have entered into firm transportation commitments to guarantee capacity totaling 10,000 barrels of crude oil per day on a major pipelinerail transportation facilities in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The transportation commitment is for crude oil production in the Bakken field where we allocate a significant portion of our capital expenditures. The commitment requiresrail commitments require us to pay varying per-barrel transportation reservation charges of $1.85 per barrel, or $6.8 million annually through August 2016, regardless of the amount of pipelinerail capacity used. The commitments under this agreementWe are not recordedcommitted under these contracts to deliver fixed and determinable quantities of crude oil in the accompanying consolidated balance sheets.future. See Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies for additional discussion. |
The Company is not committed under existing contracts
| |
| (10) | We have 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 we operate. This arrangement extends through January 2016 and requires us to make scheduled periodic payments based on the projected total cost of the project and the progress of construction. |
In addition to
deliver fixed and determinable quantities ofthe operational pipeline transportation commitments described above, we are a party to 5-year firm transportation commitments for future crude oil
pipeline projects that are being constructed or
natural gas inconsidered for development that are not yet operational. Such projects require the
future.Corporate Relocation
In March 2011, we announced plans to relocate our corporate headquarters from Enid, Oklahoma to Oklahoma City, Oklahoma. The relocation is expected to provide more convenient access to our operations acrossgranting of regulatory approvals or otherwise require significant additional construction efforts by the country, to our business partners and to an expanded pool of technical talent. The relocation is expected to be completed during 2012. We currently estimate we may incur acounterparties before being completed. Future commitments under the non-operational arrangements total of approximately $15 million to $25 million of costs in conjunction with our relocation, with the majority of such costs$1.0 billion at December 31, 2013, 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. For these reasons, these obligations have not been reflected in the secondcontractual obligations table above. Although timing is uncertain, operators have indicated that certain pipeline projects may become operational in the fourth quarter of 2014, which would obligate us for transportation charges totaling $36 million in 2014, $143 million per year in years 2015 through 2018, and third quarters of 2012. We generally expect to recognize the majority of relocation costs$106 million in our financial statements when incurred. As of December 31, 2011, we have recognized approximately $3.2 million of costs2019 associated with our relocation efforts, which are included in the caption “General and administrative expenses” in the consolidated statements of income.
those projects.
Crude Oil and Natural Gas Hedging
As part of our risk management program, we economically hedge a portion of our anticipated future crude oil and natural gas production to achieve more predictable cash flows and to reduce our exposure to fluctuations in crude oil and natural gas prices. Reducing our exposure to price volatility helps ensure we have adequate funds are available for our capital program. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions and our desire to have the cash flows needed to fund the development of our inventory of undeveloped crude oil and natural gas reserves in conjunction with our growth strategy.While the use of hedging arrangements limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. Currently, allAll of our derivative contracts are with parties that are lenders (or affiliates of lenders) under our revolving credit agreement.
facility. For a discussion of the potential risks associated with our hedging program, refer to
Part I, Item 1A. Risk Factors—Our hedging transactions existing at December 31, 2011derivative activities could result in financial losses or reduce our earnings. Our derivative contracts are settled based upon reported settlement prices on the NYMEX,commodity exchanges, with our crude oil derivatives being tied toderivative settlements based on NYMEX West Texas Intermediate (“WTI”("WTI") pricing and our natural gas derivatives being tied to Henry Hub pricing. A significant portion of our operated crude oil production in the North region is being sold in markets other than Cushing, Oklahoma and is priced, apart from transportation costs, at a premium to the WTI benchmark pricing in that market center. As such, WTI has become an unreliable reflection of the realized value of our North region crude oil production. Historically, WTI andor Inter-Continental Exchange ("ICE") pricing for Brent crude oil have fluctuated together, but in 2011 the two indices began to diverge. At this time, we believe the current pricing for Brent crude oil is more reflective of the sales prices currently being realized for our North region production. Accordingly, for recent crude oiland natural gas derivative contracts entered into subsequent to December 31, 2011, we decided to base such contracts on Brent pricing. While this approach is consistent with our current viewpoint, such viewpoint could changesettlements based on future fluctuations in WTI and Brent prices and the correlation of such prices to our realized prices. Therefore, our future hedging program may include contracts based on WTI prices, Brent prices, or a combination of both.NYMEX Henry Hub pricing. See
Please seeNotes to Consolidated Financial Statements—Note 5. Derivative Instrumentsfor further discussion of the accounting applicable to our derivative instruments, a summary of open contracts as of December 31, 20112013 and the estimated fair value of thosethe contracts as of that date. Between January 1,
20122014 and February
15, 2012,17, 2014, we entered into additional derivative contracts summarized in the tables below. None of these contracts have been designated for hedge accounting.
Crude
Oil | | | | | | | | |
Period and Type of Contract | | Bbls | | | Weighted
Average Price | |
February 2012 - December 2012 | | | | | | | | |
Swaps - ICE Brent Crude | | | 3,591,500 | | | $ | 111.12 | |
January 2013 - December 2013 | | | | | | | | |
Swaps - ICE Brent Crude | | | 1,460,000 | | | $ | 107.63 | |
Oil—ICE Brent
|
| | | | | | | |
| Period and Type of Contract | | Bbls | | Weighted
Average Price |
| January 2015 - December 2015 | |
| |
|
| Swaps - ICE Brent | | 6,205,000 |
| | $ | 100.27 |
|
Natural
Gas | | | | | | | | |
Period and Type of Contract | | MMBtus | | | Weighted
Average Price | |
February 2012 - June 2012 | | | | | | | | |
Swaps - Henry Hub | | | 1,510,000 | | | $ | 3.06 | |
July 2012 - December 2012 | | | | | | | | |
Swaps - Henry Hub | | | 3,680,000 | | | $ | 3.10 | |
January 2013 - December 2013 | | | | | | | | |
Swaps - Henry Hub | | | 7,300,000 | | | $ | 3.73 | |
Gas—NYMEX Henry Hub
|
| | | | | | | |
| Period and Type of Contract | | MMBtus | | Weighted
Average Price |
| January 2014 - December 2014 | |
| |
|
| Swaps - Henry Hub | | 40,495,000 |
| | $ | 4.26 |
|
| January 2015 - December 2015 | |
| |
|
| Swaps - Henry Hub | | 22,700,000 |
| | $ | 4.27 |
|
| January 2016 - December 2016 | |
|
| |
|
|
| Swaps - Henry Hub | | 4,550,000 |
| | $ | 4.27 |
|
Critical Accounting Policies and Estimates
Our
historical consolidated financial statements and related footnotes contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires our management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure
and estimation of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of existing rules must be done and judgments must be made on how the specifics of a given rule apply to us.
In management’s opinion, the most significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimations, revenue recognition, the choice of accounting method for crude oil and natural gas activities and derivatives, impairment of assets,
income taxes and
income taxes.contingent liabilities. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.
Crude Oil and Natural Gas Reserves Estimation and Standardized Measure of Future Cash Flows
Our external independent reserve engineers and internal technical staff prepare the estimates of our crude oil and natural gas reserves and associated future net cash flows.
The SEC has defined proved reserves as the estimated quantities of crude oil, natural gas and natural gas liquids 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. Even though our external independent reserve engineers and internal technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates.
Estimates of reserves and their values, future production rates, and future costs and expenses are inherently uncertain for various reasons, including many factors beyond the Company's control. Reserve estimates are updated at least
annuallysemi-annually and take into account recent production levels and other technical information about each of our fields. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of 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. Accordingly, reserve estimates are often differentmay differ significantly from the quantities of crude oil and natural gas ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If suchEstimates of proved reserves are key components of the Company's most significant financial estimates including the computation of depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Future revisions are significant, theyof reserves may be material and could significantly alter future DD&Adepreciation, depletion, and amortization expense and may result in material impairments of assets.
We derive substantially all of our revenues from the sale of crude oil and natural gas. Crude oil and natural gas revenues are
recordedrecognized in the month the product is delivered to the purchaser and title transfers. We generally receive payment from one to three months after the sale has occurred.
Each monthWe use the sales method of accounting for natural gas imbalances in those circumstances where we
estimatehave under-produced or over-produced our ownership percentage in a property. Under this method, a receivable or payable is recognized only to the
volumes sold andextent an imbalance cannot be recouped from the
price at which they were sold to record revenue. Variances between estimated revenues and actual amounts are recordedreserves in the
month payment is received and are reflected in our consolidated statements of income as crude oil and natural gas sales. These variances have historically not been material.underlying properties.
Successful Efforts Method of Accounting
We use the successful efforts method of accounting for our crude oil and natural gas properties, whereby
we capitalize costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery
operations.operations are capitalized. Geological and geophysical costs, seismic costs
incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred.
Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the
costcosts of replacements or renewals that expand capacity or improve production are capitalized.
Depreciation, depletion, and amortization of capitalized drilling and development costs of crude oil and natural gas properties, including related support equipment and facilities, are generally computed using the unit-of-production method on a field basis
based on total estimated proved developed crude oil and natural gas reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by our internal geologists and engineers and external independent reserve engineers. Service properties, equipment and other assets are depreciated using the straight-line method over estimated useful lives of 3 to 40 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized.
Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
We utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our future crude oil and natural gas production. In addition, we may utilize basis contracts to hedge the differential between NYMEX
Henry Hub posted prices and those of our physical pricing points. We do not use derivative instruments for trading purposes. Under accounting rules, we may elect to designate those derivatives that qualify for hedge accounting as cash flow hedges against the price we will receive for our future crude oil and natural gas production. We have elected not to designate any of our price risk management activities as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the
realized and unrealized changes in fair value in current earnings. As such, we are likely to experience significant non-cash volatility in our reported earnings during periods of commodity price volatility. Derivative assets and liabilities with the same counterparty and subject to contractual terms which provide for net settlement are reported on a net basis on our consolidated balance sheets.
In determining the amounts to be recorded for our open derivative contracts, we are required to estimate the fair value of the derivatives. We use an independent third party to provide our derivative valuations. The third party’s
valuation models for derivative contracts are industry-standard models that consider 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. The calculation of the fair value of our collar contracts requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative agreements and the resulting estimated future cash inflows or outflows over the lives of the derivatives are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates. We validate our derivative valuations through management reviewsreview and by comparison to our counterparties’ valuations for reasonableness.
All of our long-lived assets are monitored for potential impairment when circumstances indicate the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk adjusted proved reserves.
For producing properties, the evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce those products, estimates of future crude oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or downward revisions to crude oil and natural gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and are subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.
Non-producing crude oil and natural gas properties, which consist primarily of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves, are assessed for impairment on a property-by-property basis for individually significant balances, if any, and on an aggregate basis by prospect for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level consistent with the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. For individually insignificant non-producing properties,
the amount of the impairment
losslosses are recognized
is determined by amortizing the portion of the
unproved properties’ costs which management estimates will not be transferred to proved properties over the
lifelives of the
leaseleases based on experience of successful drilling and the average holding period. The estimated rate of successful drilling is highly judgmental and is subject to material revision in future periods as better information becomes available.
We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain deferred tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets. If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31,
2011,2013, we believe all deferred tax assets recorded on our consolidated balance sheets will ultimately be utilized. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly related to prevailing crude oil and natural gas prices). If our estimates and judgments
change regarding our ability to utilize our deferred tax assets, our tax provision could increase in the period it is determined that it is more likely than not that a deferred tax asset will not be utilized.
Our effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax-paying companies. Our effective tax rate is affected by changes in the allocation of property, payroll, and revenues between states in which we own property as rates vary from state to state. Due to the size of our gross deferred tax balances, a small change in our estimated future tax rate can have a material effect on current period earnings.
Contingent Liabilities
A provision for legal, environmental and other contingencies is charged to expense when a loss is probable and the loss or range of loss can be reasonably estimated. Determining when liabilities and expenses should be recorded for these contingencies and the appropriate amounts of accruals is subject to an estimation process that requires subjective judgment of management. In certain cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. Actual losses can differ from estimates for various reasons, including differing interpretations of laws and opinions and assessments on the amount of damages. We closely monitor known and potential legal, environmental and other contingencies and make our best estimate of when or if to record liabilities and losses for matters based on available information.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resources. However, as is customary in the crude oil and natural gas industry, we have various contractual commitments that are not reflected in the consolidated balance sheets as shown underPart II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations. Recent Accounting Pronouncements Not Yet Adopted
In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04,Fair Value Measurement (Topic 820)–Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.The amendments in ASU No. 2011-04 are the result of work by the FASB and the International Accounting Standards Board (“IASB”) to develop common global requirements for measuring fair value and for disclosing information about fair value measurements to improve the comparability of financial statements prepared in accordance with U.S. GAAP and IFRS. Many of the amendments in ASU No. 2011-04 offer clarification to existing guidance and are not intended to result in significant changes in the application of the fair value measurement guidance of U.S. GAAP. The new standard is effective for the first interim or annual reporting period beginning after December 15, 2011 and is required to be applied prospectively. We will adopt the requirements of ASU No. 2011-04 on January 1, 2012, which may require additional footnote disclosures for our derivative instruments and is not expected to have a material effect on our financial position, results of operations or cash flows.
In December 2011, the FASB issued ASU No. 2011-11,Balance Sheet (Topic 210)–Disclosures about Offsetting Assets and Liabilities. The new standard requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The disclosures are required for recognized financial instruments and derivative instruments that are subject to offsetting under current accounting literature or are subject to master netting arrangements irrespective of whether they are offset. The objective of the new disclosures is to facilitate comparison between entities that prepare financial statements on the basis of U.S. GAAP and entities that prepare financial statements under IFRS. The disclosure requirements will be effective for periods beginning on or after January 1, 2013 and must be applied retrospectively to all periods presented on the balance sheet. We will adopt the requirements of ASU No. 2011-11 on January 1, 2013, which may require additional footnote disclosures for our derivative instruments and is not expected to have a material effect on our financial position, results of operations or cash flows.
We are monitoring the joint standard-setting efforts of the
FASBFinancial Accounting Standards Board and
IASB.International Accounting Standards Board. There are a number of pending accounting standards being targeted for completion in
20122014 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements,
and accounting for financial
instruments, disclosure of loss contingencies and financial statement presentation.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.
Pending Legislative and Regulatory Initiatives
The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and regulationsinterpretations affecting the crude oil and natural gasour industry have been pervasive and are under continual reviewcontinuously reviewed by legislators and regulators, including the imposition of new or increased requirements on us and other industry participants. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for amendment or expansion. The following area discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.Dodd-Frank Wall Street Reform and Consumer Protection Act.In July 2010, the Dodd-Frank Act was enacted into law. This financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules and regulations to implement the new legislation. The CFTC has issued final regulations to implement significant aspects of the legislation, including new rules for the registration of swap dealers and major swap participants, requirements for reporting and recordkeeping, rules on customer protection We believe we are in the context of cleared swaps, and position limits for swaps and other transactions based on the price of certain reference contracts, some of which are referenced in our swap contracts. Key regulations not yet finalized include those clarifying the definitions of “swap dealer,” “major swap participant” and “swap” and those establishing margin requirements for uncleared swaps and various trade execution and trade documentation requirements. These regulations may require or cause our counterparties to collect margin from us and may require us to clear our transactions or execute them on a derivatives contract market or swap execution facility, although the application of these provisions to us is uncertain at this time. The ultimate effect of the proposed new rules and any additional regulations on our business is uncertain. Of particular concern to us is whether the provisions of the final rules and regulations will allow us to qualify as a non-financial, commercial end user that is exempt from the requirement to clear our derivative contracts, and whether our status will allow our derivative counterparties to not require us to post margin in connectionsubstantial compliance with our commodity price risk management activities. The remaining final rules and regulations on major provisions of the legislation, such as new margin requirements, are to be established through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area, to the extent applicable to us or our derivative counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial and commercial risks related to fluctuations in commodity prices, increased regulatory reporting and recordkeeping, and market dislocations or disruptions, among other consequences, and could have an adverse effect on our ability to hedge risks associated with our business. Further, the Dodd-Frank Act requires the SEC to develop rules that would require certain registrants to disclose payments they make to the U.S. Federal Government or foreign governments related to the commercial development of crude oil and natural gas. The proposed rules related to government payments are not yet finalized and the application of such rules to us is uncertain.
Climate change. Federal, state and localall laws and regulations are increasingly being enacted to address concerns about the effects the emission of carbon dioxide and other identified “greenhouse gases” may have on the environment and climate worldwide. These effects are widely referred to as “climate change.” Since its December 2009 endangerment finding regarding the emission of carbon dioxide, methane and other greenhouse gases, the EPA has begun regulating sources of greenhouse gas emissions under the federal Clean Air Act. Among several regulations requiring reporting or permitting for greenhouse gas sources, the EPA finalized its “tailoring rule” in May 2010 that determines which stationary sources of greenhouse gases are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology for, their greenhouse gases. In November 2010, the EPA also finalized its greenhouse gas reporting requirements, beginning in March 2012, for certain oil and gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. Wepolicies currently estimate our producing wells in five basins will be subject to the reporting requirements.
Moreover, in recent past the U.S. Congress has considered establishing a cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. Under past proposals, the EPA would issue or sell a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of such legislation, if ever adopted, would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil,
refined petroleum products, and natural gas. In addition, while the prospect for such cap-and-trade legislation by the U.S. Congress remains uncertain, several states, including states in which we operate, have adopted, or are in the process of adopting, similar cap-and-trade programs.
As a crude oil and natural gas company, the debate on climate change is relevantapplicable to our operations because the equipment we use to explore for, develop and produce crude oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the crude oil and natural gas we sell, emits carbon dioxide and other greenhouse gases. Thus, any current or future federal, state or local climate change initiatives could adversely affect demand for the crude oil and natural gas we produce by stimulating demand for alternative forms of energy that doour continued compliance with existing requirements will not rely on the combustion of fossil fuels, and therefore could have a material adverse effectimpact on us. However, because public policy changes affecting our business. Although our compliance with any greenhouse gasindustry are commonplace and because laws and regulations may result in increased compliance and operating costs, we do not expect the compliance costs for currently applicable regulations to be material. Moreover, while it is not possible at this time to estimate the compliance costsamended or operational impacts for any new legislative or regulatory developments in this area, we do not anticipate being impacted to any greater degree than other similarly situated competitors.
Hydraulic fracturing. Some activists have attempted to link hydraulic fracturing to various environmental problems, including adverse effects to drinking water supplies and migration of methane and other hydrocarbons. As a result, several federal agencies are studying the environmental risks with respect to hydraulic fracturing or evaluating whether to restrict its use. From time to time, legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities from the definition of “underground injection,” thereby requiring the crude oil and natural gas industry to obtain permits for hydraulic fracturing and to require disclosure of the additives used in the process. If ever adopted, such legislation could establish an additional level of regulation and permitting at the federal level. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the initial results of which are anticipated to be available by late 2012. The U.S. Department of the Interior has announced it will publish rules requiring companies to disclose the make-up of all materials used in hydraulic fracturing fluids on federal lands. The announced legislation will also require disclosure of the source, access route and transport of all water anticipated to be used in connection with hydraulic fracturing operations. The announced rules have not been published andreinterpreted, we are not ableunable to determinepredict the extentfuture cost or impact of their impact on our operations on federal land. In addition to these federal initiatives, several statecomplying with such laws and local governments, including states in which we operate, have moved to require disclosure of fracturing fluid components or otherwise to regulate their use more closely. regulations.
Inflation
In
certain areas of the United States, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards. The adoption of any future federal, state or local laws or implementing regulations imposing permitting or reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult and more expensive to complete crude oil and natural gas wells in low-permeability formations and increase our costs of compliance and doing business, as well as delay, prevent or prohibit the development of natural resources from unconventional formations. Compliance, or the consequences of any failure to comply by us, could have a material adverse effect on our financial condition and results of operations. At this time it is not possible to estimate the potential impact on our business that may arise if federal or state legislation is enacted into law.Inflation
Historically, general inflationary trends have not had a material effect on our operating results. However, in recent years we have experienced inflationary pressure on technical staff compensation and the cost of oilfield services and equipment due to increases in drilling activity, particularly in the North region, and competitive pressures resulting from higher crude oil prices.
prices and may again in the future.
Non-GAAP Financial Measures
We present EBITDAX throughout this Annual Report on Form 10-K, which is a non-GAAP financial measure. EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and
accretion, property impairments, exploration expenses, unrealized derivativenon-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 thosethese 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 credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
We believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our credit facility requires that we maintain a total funded debt to EBITDAX ratio of no greater than 3.754.0 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 December 31, 2011. At that date, our total funded debt to EBITDAX ratio was 1.0 to 1.0. A violation of this covenant in the future could result in a default under our credit facility. In the event of such default, the lenders under our credit facility could elect to terminate their commitments thereunder, cease making further loans, and could declare all outstanding amounts, together with accrued interest, to be due and payable. If the indebtedness under our credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness. Our credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. 2013.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented. | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | |
in thousands | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
Net income | | $ | 429,072 | | | $ | 168,255 | | | $ | 71,338 | | | $ | 320,950 | | | $ | 28,580 | |
Interest expense | | | 76,722 | | | | 53,147 | | | | 23,232 | | | | 12,188 | | | | 12,939 | |
Provision for income taxes | | | 258,373 | | | | 90,212 | | | | 38,670 | | | | 197,580 | | | | 268,197 | |
Depreciation, depletion, amortization and accretion | | | 390,899 | | | | 243,601 | | | | 207,602 | | | | 148,902 | | | | 93,632 | |
Property impairments | | | 108,458 | | | | 64,951 | | | | 83,694 | | | | 28,847 | | | | 17,879 | |
Exploration expenses | | | 27,920 | | | | 12,763 | | | | 12,615 | | | | 40,160 | | | | 9,163 | |
Unrealized (gains) losses on derivatives | | | (4,057 | ) | | | 166,257 | | | | 2,089 | | | | — | | | | 26,703 | |
Non-cash equity compensation | | | 16,572 | | | | 11,691 | | | | 11,408 | | | | 9,081 | | | | 12,792 | |
| | | | | | | | | | | | | | | | | | | | |
EBITDAX | | $ | 1,303,959 | | | $ | 810,877 | | | $ | 450,648 | | | $ | 757,708 | | | $ | 469,885 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 | | 2010 | | 2009 |
| Net income | | $ | 764,219 |
| | $ | 739,385 |
| | $ | 429,072 |
| | $ | 168,255 |
| | $ | 71,338 |
|
| Interest expense | | 235,275 |
| | 140,708 |
| | 76,722 |
| | 53,147 |
| | 23,232 |
|
| Provision for income taxes | | 448,830 |
| | 415,811 |
| | 258,373 |
| | 90,212 |
| | 38,670 |
|
| Depreciation, depletion, amortization and accretion | | 965,645 |
| | 692,118 |
| | 390,899 |
| | 243,601 |
| | 207,602 |
|
| Property impairments | | 220,508 |
| | 122,274 |
| | 108,458 |
| | 64,951 |
| | 83,694 |
|
| Exploration expenses | | 34,947 |
| | 23,507 |
| | 27,920 |
| | 12,763 |
| | 12,615 |
|
| Impact from derivative instruments: | |
| |
| |
| |
| |
|
| Total (gain) loss on derivatives, net | | 191,751 |
| | (154,016 | ) | | 30,049 |
| | 130,762 |
| | 1,520 |
|
| Total cash (paid) received on derivatives, net | | (61,555 | ) | | (45,721 | ) | | (34,106 | ) | | 35,495 |
| | 569 |
|
| Non-cash (gain) loss on derivatives, net | | 130,196 |
| | (199,737 | ) | | (4,057 | ) | | 166,257 |
| | 2,089 |
|
| Non-cash equity compensation | | 39,890 |
| | 29,057 |
| | 16,572 |
| | 11,691 |
| | 11,408 |
|
| EBITDAX | | $ | 2,839,510 |
| | $ | 1,963,123 |
| | $ | 1,303,959 |
| | $ | 810,877 |
| | $ | 450,648 |
|
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 | | 2010 | | 2009 |
| Net cash provided by operating activities | | $ | 2,563,295 |
| | $ | 1,632,065 |
| | $ | 1,067,915 |
| | $ | 653,167 |
| | $ | 372,986 |
|
| Current income tax provision | | 6,209 |
| | 10,517 |
| | 13,170 |
| | 12,853 |
| | 2,551 |
|
| Interest expense | | 235,275 |
| | 140,708 |
| | 76,722 |
| | 53,147 |
| | 23,232 |
|
| Exploration expenses, excluding dry hole costs | | 25,597 |
| | 22,740 |
| | 19,971 |
| | 9,739 |
| | 6,138 |
|
| Gain on sale of assets, net | | 88 |
| | 136,047 |
| | 20,838 |
| | 29,588 |
| | 709 |
|
| Excess tax benefit from stock-based compensation | | — |
| | 15,618 |
| | — |
| | 5,230 |
| | 2,872 |
|
| Other, net | | (1,829 | ) | | (7,587 | ) | | (4,606 | ) | | (3,513 | ) | | (3,890 | ) |
| Changes in assets and liabilities | | 10,875 |
| | 13,015 |
| | 109,949 |
| | 50,666 |
| | 46,050 |
|
| EBITDAX | | $ | 2,839,510 |
| | $ | 1,963,123 |
| | $ | 1,303,959 |
| | $ | 810,877 |
| | $ | 450,648 |
|
Our PV-10 value, a non-GAAP financial measure, is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31,
2011,2013, our PV-10 totaled approximately
$9.2$20.2 billion. The Standardized Measure of our discounted future net cash flows was approximately
$7.5$16.3 billion at December 31,
2011,2013, representing a
$1.7$3.9 billion difference from PV-10
becausedue to the effect of
the tax effect.deducting estimated future income taxes in arriving at Standardized Measure. We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific
income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties.
| |
| Item 7A. | 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 production 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 price.prices. Based on our average daily production for the year ended December 31, 20112013 and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $165$350 million for each $10.00 per barrel change in crude oil prices and $37$88 million for each $1.00 per Mcf change in natural gas prices. To
partially reduce price risk caused by these market fluctuations, we
periodicallyeconomically 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
NYMEXderivative 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 year ended December 31, 2013 had an overall negative impact on the fair value of our derivative instruments. For the year ended December 31,
2011,2013, we
realized gainsrecognized cash losses on
natural gas derivatives of
$37.3$61.6 million and
realized losses on crude oil derivatives of $71.4 million. For the year ended December 31, 2011, we reported
an unrealized non-cash mark-to-market gain on crude oil derivatives of $18.8 million and an unrealizeda non-cash mark-to-market loss on
natural gas derivatives of
$14.7$130.2 million. The fair value of our derivative instruments at December 31,
20112013 was a net liability of
$164.3$94.7 million.
ThisThe mark-to-market net liability
representing an unrealized mark-to-market loss, relates to derivative instruments with various terms that are scheduled to
be realizedmature over the period from January
20122014 through December
2013.2015. Over this period, actual
realized derivative settlements may differ significantly, either positively or negatively, from the
unrealized mark-to-market valuation at December 31,
2011.2013. An assumed increase in the forward commodity prices used in the year-end 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
$414$485 million at December 31,
2011.2013. 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
$75$289 million at December 31,
2011.2013.
For a further discussion of our hedging activities, seePart II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Crude Oil and Natural Gas Hedging andPart II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments appearing in this Annual Report..
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 ($378.8656.2 million in receivables at December 31, 2011)2013), our joint interest receivables ($398.8350.0 million at December 31, 2011)2013), and counterparty credit risk associated with our derivative instrument receivables ($10.33.6 million at December 31, 2011)2013). 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
$52.8$57.2 million as of December 31,
2011,2013, 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.
Currently, allAll of our derivative contracts are with parties that are lenders (or affiliates of lenders) under our
revolving 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 revolving 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. 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 $900.0$560 million of outstanding borrowings under our revolving credit facility at February 15, 2012.17, 2014. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $9.0$5.6 million per year and a $5.6$3.5 million decrease in net income per year. Our revolving credit facility matures on July 1, 2015 and the weighted-average interest rate on outstanding borrowings at February 15, 201217, 2014 was 2.8%1.7%. The following table presents our
long-term debt maturities and the weighted average interest rates by expected maturity date as of December 31,
2011: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
In thousands | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | Thereafter | | | Total | |
Fixed rate debt: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Senior Notes: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Principal amount (1) | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 900.0 | | | $ | 900.0 | |
Weighted-average interest rate | | | | | | | | | | | | | | | | | | | | | | | 7.6 | % | | | 7.6 | % |
Variable rate debt: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revolving credit facility: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Principal amount | | $ | — | | | $ | — | | | $ | — | | | $ | 358.0 | | | $ | — | | | $ | — | | | $ | 358.0 | |
Weighted-average interest rate | | | | | | | | | | | | | | | 2.0 | % | | | | | | | | | | | 2.0 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| In thousands | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | Thereafter | | Total |
| Fixed rate debt: | |
| |
| |
| |
| |
| |
| |
|
| Senior Notes: | |
| |
| |
| |
| |
| |
| |
|
| Principal amount (1) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4,400,000 |
| | $ | 4,400,000 |
|
| Weighted-average interest rate | | — |
| | — |
| | — |
| | — |
| | — |
| | 5.4 | % | | 5.4 | % |
| Note payable: | |
| |
| |
| |
| |
| |
| |
|
| Principal amount | | $ | 2,011 |
| | $ | 2,078 |
| | $ | 2,144 |
| | $ | 2,214 |
| | $ | 2,286 |
| | $ | 7,737 |
| | $ | 18,470 |
|
| Interest rate | | 3.1 | % | | 3.1 | % | | 3.1 | % | | 3.1 | % | | 3.1 | % | | 3.1 | % | | 3.1 | % |
| Variable rate debt: | |
| |
| |
| |
| |
| |
| |
|
| Credit facility: | |
| |
| |
| |
| |
| |
| |
|
| Principal amount | | $ | — |
| | $ | 275,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 275,000 |
|
| Weighted-average interest rate | | — |
| | 1.7 | % | | — |
| | — | | — | | — | | 1.7 | % |
| |
| (1) | Amount does not reflect the discountsany discount or premium at which the Senior Notessenior notes were issued. |
Changes in interest rates affect the
amountamounts we pay on borrowings under our
revolving credit facility. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates. However, changes in interest rates do affect the fair values of our
Senior Notes.senior notes and note payable.
| |
| Item 8. | Financial Statements and Supplementary Data |
Index to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Continental Resources, Inc.
We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and Subsidiaries (the
“Company”)Company) as of December 31,
20112013 and
2010,2012, and the related consolidated statements of income, shareholders’ equity and cash flows for each of the three years in the period ended December 31,
2011.2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Continental Resources, Inc. and Subsidiaries as of December 31,
20112013 and
2010,2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31,
2011,2013 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011,2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 24, 201226, 2014 expressed an unqualified opinion.
February 24, 201226, 2014
Continental Resources, Inc. and Subsidiaries
Consolidated Balance Sheets | | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | |
| | | In thousands, except par
values and share data | |
Assets | | | | | | | | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 53,544 | | | $ | 7,916 | |
Receivables: | | | | | | | | |
Crude oil and natural gas sales | | | 366,441 | | | | 208,211 | |
Affiliated parties | | | 31,108 | | | | 20,156 | |
Joint interest and other, net | | | 379,991 | | | | 254,471 | |
Derivative assets | | | 6,669 | | | | 21,365 | |
Inventories | | | 41,270 | | | | 38,362 | |
Deferred and prepaid taxes | | | 47,658 | | | | 22,672 | |
Prepaid expenses and other | | | 9,692 | | | | 9,173 | |
| | | | | | | | |
Total current assets | | | 936,373 | | | | 582,326 | |
Net property and equipment, based on successful efforts method of accounting | | | 4,681,733 | | | | 2,981,991 | |
Net debt issuance costs and other | | | 24,355 | | | | 27,468 | |
Noncurrent derivative assets | | | 3,625 | | | | — | |
| | | | | | | | |
Total assets | | $ | 5,646,086 | | | $ | 3,591,785 | |
| | | | | | | | |
Liabilities and shareholders’ equity | | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable trade | | $ | 642,889 | | | $ | 390,892 | |
Revenues and royalties payable | | | 222,027 | | | | 133,051 | |
Payables to affiliated parties | | | 9,939 | | | | 4,438 | |
Accrued liabilities and other | | | 117,674 | | | | 94,829 | |
Derivative liabilities | | | 116,985 | | | | 76,771 | |
Current portion of asset retirement obligations | | | 2,287 | | | | 2,241 | |
| | | | | | | | |
Total current liabilities | | | 1,111,801 | | | | 702,222 | |
Long-term debt | | | 1,254,301 | | | | 925,991 | |
Other noncurrent liabilities: | | | | | | | | |
Deferred income tax liabilities | | | 850,282 | | | | 582,841 | |
Asset retirement obligations, net of current portion | | | 60,338 | | | | 54,079 | |
Noncurrent derivative liabilities | | | 57,598 | | | | 112,940 | |
Other noncurrent liabilities | | | 3,640 | | | | 5,557 | |
| | | | | | | | |
Total other noncurrent liabilities | | | 971,858 | | | | 755,417 | |
Commitments and contingencies (Note 10) | | | | | | | | |
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; 180,871,688 shares issued and outstanding at December 31, 2011; 170,408,652 shares issued and outstanding at December 31, 2010 | | | 1,809 | | | | 1,704 | |
Additional paid-in capital | | | 1,110,694 | | | | 439,900 | |
Retained earnings | | | 1,195,623 | | | | 766,551 | |
| | | | | | | | |
Total shareholders’ equity | | | 2,308,126 | | | | 1,208,155 | |
| | | | | | | | |
Total liabilities and shareholders’ equity | | $ | 5,646,086 | | | $ | 3,591,785 | |
| | | | | | | | |
|
| | | | | | | | |
| | | December 31, |
| In thousands, except par values and share data | | 2013 | | 2012 |
| Assets | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 28,482 |
| | $ | 35,729 |
|
| Receivables: | | | | |
| Crude oil and natural gas sales | | 643,498 |
| | 468,650 |
|
| Affiliated parties | | 13,107 |
| | 12,410 |
|
| Joint interest and other, net | | 349,579 |
| | 356,111 |
|
| Derivative assets | | 3,616 |
| | 18,389 |
|
| Inventories | | 54,440 |
| | 46,743 |
|
| Deferred and prepaid taxes | | 44,337 |
| | 365 |
|
| Prepaid expenses and other | | 10,207 |
| | 8,386 |
|
| Total current assets | | 1,147,266 |
| | 946,783 |
|
| Net property and equipment, based on successful efforts method of accounting | | 10,721,272 |
| | 8,105,269 |
|
| Net debt issuance costs and other | | 72,644 |
| | 55,726 |
|
| Noncurrent derivative assets | | — |
| | 32,231 |
|
| Total assets | | $ | 11,941,182 |
| | $ | 9,140,009 |
|
| | | | | |
| Liabilities and shareholders’ equity | | | | |
| Current liabilities: | | | | |
| Accounts payable trade | | $ | 885,289 |
| | $ | 687,310 |
|
| Revenues and royalties payable | | 291,772 |
| | 261,856 |
|
| Payables to affiliated parties | | 5,436 |
| | 6,069 |
|
| Accrued liabilities and other | | 198,113 |
| | 155,681 |
|
| Derivative liabilities | | 90,535 |
| | 12,999 |
|
| Current portion of long-term debt | | 2,011 |
| | 1,950 |
|
| Total current liabilities | | 1,473,156 |
| | 1,125,865 |
|
| Long-term debt, net of current portion | | 4,713,821 |
| | 3,537,771 |
|
| Other noncurrent liabilities: | | | | |
| Deferred income tax liabilities | | 1,736,812 |
| | 1,262,576 |
|
| Asset retirement obligations, net of current portion | | 54,353 |
| | 44,944 |
|
| Noncurrent derivative liabilities | | 7,829 |
| | 2,173 |
|
| Other noncurrent liabilities | | 2,093 |
| | 2,981 |
|
| Total other noncurrent liabilities | | 1,801,087 |
| | 1,312,674 |
|
| Commitments and contingencies (Note 10) | |
| |
|
| 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; | | | | |
| 185,658,659 shares issued and outstanding at December 31, 2013; | | | | |
| 185,604,681 shares issued and outstanding at December 31, 2012 | | 1,857 |
| | 1,856 |
|
| Additional paid-in capital | | 1,252,034 |
| | 1,226,835 |
|
| Retained earnings | | 2,699,227 |
| | 1,935,008 |
|
| Total shareholders’ equity | | 3,953,118 |
| | 3,163,699 |
|
| Total liabilities and shareholders’ equity | | $ | 11,941,182 |
| | $ | 9,140,009 |
|
The accompanying notes are an integral part of these consolidated financial statements.
69
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Income
| | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands, except per share data | |
Revenues: | | | | | | | | | | | | |
Crude oil and natural gas sales | | $ | 1,553,629 | | | $ | 917,503 | | | $ | 584,089 | |
Crude oil and natural gas sales to affiliates | | | 93,790 | | | | 31,021 | | | | 26,609 | |
Loss on derivative instruments, net | | | (30,049 | ) | | | (130,762 | ) | | | (1,520 | ) |
Crude oil and natural gas service operations | | | 32,419 | | | | 21,303 | | | | 17,033 | |
| | | | | | | | | | | | |
Total revenues | | | 1,649,789 | | | | 839,065 | | | | 626,211 | |
| | | |
Operating costs and expenses: | | | | | | | | | | | | |
Production expenses | | | 135,178 | | | | 86,557 | | | | 76,719 | |
Production and other expenses to affiliates | | | 4,632 | | | | 6,646 | | | | 16,523 | |
Production taxes and other expenses | | | 143,236 | | | | 76,659 | | | | 45,645 | |
Exploration expenses | | | 27,920 | | | | 12,763 | | | | 12,615 | |
Crude oil and natural gas service operations | | | 26,735 | | | | 18,065 | | | | 10,740 | |
Depreciation, depletion, amortization and accretion | | | 390,899 | | | | 243,601 | | | | 207,602 | |
Property impairments | | | 108,458 | | | | 64,951 | | | | 83,694 | |
General and administrative expenses | | | 72,817 | | | | 49,090 | | | | 41,094 | |
Gain on sale of assets, net | | | (20,838 | ) | | | (29,588 | ) | | | (709 | ) |
| | | | | | | | | | | | |
Total operating costs and expenses | | | 889,037 | | | | 528,744 | | | | 493,923 | |
| | | | | | | | | | | | |
Income from operations | | | 760,752 | | | | 310,321 | | | | 132,288 | |
Other income (expense): | | | | | | | | | | | | |
Interest expense | | | (76,722 | ) | | | (53,147 | ) | | | (23,232 | ) |
Other | | | 3,415 | | | | 1,293 | | | | 952 | |
| | | | | | | | | | | | |
| | | (73,307 | ) | | | (51,854 | ) | | | (22,280 | ) |
| | | | | | | | | | | | |
Income before income taxes | | | 687,445 | | | | 258,467 | | | | 110,008 | |
Provision for income taxes | | | 258,373 | | | | 90,212 | | | | 38,670 | |
| | | | | | | | | | | | |
Net income | | $ | 429,072 | | | $ | 168,255 | | | $ | 71,338 | |
| | | | | | | | | | | | |
Basic net income per share | | $ | 2.42 | | | $ | 1.00 | | | $ | 0.42 | |
Diluted net income per share | | $ | 2.41 | | | $ | 0.99 | | | $ | 0.42 | |
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| In thousands, except per share data | | 2013 | | 2012 | | 2011 |
| Revenues: | | | | | | |
| Crude oil and natural gas sales | | $ | 3,501,666 |
| | $ | 2,315,840 |
| | $ | 1,553,629 |
|
| Crude oil and natural gas sales to affiliates | | 105,108 |
| | 63,593 |
| | 93,790 |
|
| Gain (loss) on derivative instruments, net | | (191,751 | ) | | 154,016 |
| | (30,049 | ) |
| Crude oil and natural gas service operations | | 40,127 |
| | 39,071 |
| | 32,419 |
|
| Total revenues | | 3,455,150 |
| | 2,572,520 |
| | 1,649,789 |
|
| | | | | | | |
| Operating costs and expenses: | | | | | | |
| Production expenses | | 280,789 |
| | 193,466 |
| | 135,178 |
|
| Production and other expenses to affiliates | | 6,111 |
| | 6,675 |
| | 4,632 |
|
| Production taxes and other expenses | | 327,427 |
| | 223,737 |
| | 143,236 |
|
| Exploration expenses | | 34,947 |
| | 23,507 |
| | 27,920 |
|
| Crude oil and natural gas service operations | | 29,665 |
| | 32,248 |
| | 26,735 |
|
| Depreciation, depletion, amortization and accretion | | 965,645 |
| | 692,118 |
| | 390,899 |
|
| Property impairments | | 220,508 |
| | 122,274 |
| | 108,458 |
|
| General and administrative expenses | | 144,379 |
| | 121,735 |
| | 72,817 |
|
| Gain on sale of assets, net | | (88 | ) | | (136,047 | ) | | (20,838 | ) |
| Total operating costs and expenses | | 2,009,383 |
| | 1,279,713 |
| | 889,037 |
|
| Income from operations | | 1,445,767 |
| | 1,292,807 |
| | 760,752 |
|
| Other income (expense): | | | | | | |
| Interest expense | | (235,275 | ) | | (140,708 | ) | | (76,722 | ) |
| Other | | 2,557 |
| | 3,097 |
| | 3,415 |
|
| | | (232,718 | ) | | (137,611 | ) | | (73,307 | ) |
| Income before income taxes | | 1,213,049 |
| | 1,155,196 |
| | 687,445 |
|
| Provision for income taxes | | 448,830 |
| | 415,811 |
| | 258,373 |
|
| Net income | | $ | 764,219 |
| | $ | 739,385 |
| | $ | 429,072 |
|
| Basic net income per share | | $ | 4.15 |
| | $ | 4.08 |
| | $ | 2.42 |
|
| Diluted net income per share | | $ | 4.13 |
| | $ | 4.07 |
| | $ | 2.41 |
|
The accompanying notes are an integral part of these consolidated financial statements.
70
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Shareholders’ Equity
| | | | | | | | | | | | | | | | | | | | |
| | | Shares
outstanding | | | Common
stock | | | Additional
paid-in
capital | | | Retained
earnings | | | Total
shareholders’
equity | |
| | | | | |
| | | | | |
| | | In thousands, except share data | |
Balance, December 31, 2008 | | | 169,558,129 | | | $ | 1,696 | | | $ | 420,054 | | | $ | 526,958 | | | $ | 948,708 | |
Net income | | | — | | | | — | | | | — | | | | 71,338 | | | | 71,338 | |
Stock-based compensation | | | — | | | | — | | | | 11,408 | | | | — | | | | 11,408 | |
Excess tax benefit on stock-based compensation | | | — | | | | — | | | | 2,872 | | | | — | | | | 2,872 | |
Stock options: | | | | | | | | | | | | | | | | | | | | |
Exercised | | | 138,010 | | | | 1 | | | | 244 | | | | — | | | | 245 | |
Repurchased and canceled | | | (29,924 | ) | | | — | | | | (1,223 | ) | | | — | | | | (1,223 | ) |
Restricted stock: | | | | | | | | | | | | | | | | | | | | |
Issued | | | 411,217 | | | | 4 | | | | — | | | | — | | | | 4 | |
Repurchased and canceled | | | (83,457 | ) | | | (1 | ) | | | (3,072 | ) | | | — | | | | (3,073 | ) |
Forfeited | | | (25,504 | ) | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2009 | | | 169,968,471 | | | $ | 1,700 | | | $ | 430,283 | | | $ | 598,296 | | | $ | 1,030,279 | |
Net income | | | — | | | | — | | | | — | | | | 168,255 | | | | 168,255 | |
Stock-based compensation | | | — | | | | — | | | | 11,691 | | | | — | | | | 11,691 | |
Excess tax benefit on stock-based compensation | | | — | | | | — | | | | 5,230 | | | | — | | | | 5,230 | |
Stock options: | | | | | | | | | | | | | | | | | | | | |
Exercised | | | 207,220 | | | | 2 | | | | 255 | | | | — | | | | 257 | |
Repurchased and canceled | | | (59,877 | ) | | | (1 | ) | | | (2,661 | ) | | | — | | | | (2,662 | ) |
Restricted stock: | | | | | | | | | | | | | | | | | | | | |
Issued | | | 449,114 | | | | 4 | | | | — | | | | — | | | | 4 | |
Repurchased and canceled | | | (100,561 | ) | | | (1 | ) | | | (4,898 | ) | | | — | | | | (4,899 | ) |
Forfeited | | | (55,715 | ) | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2010 | | | 170,408,652 | | | $ | 1,704 | | | $ | 439,900 | | | $ | 766,551 | | | $ | 1,208,155 | |
Net income | | | — | | | | — | | | | — | | | | 429,072 | | | | 429,072 | |
Public offering of common stock | | | 10,080,000 | | | | 101 | | | | 659,131 | | | | — | | | | 659,232 | |
Stock-based compensation | | | — | | | | — | | | | 16,567 | | | | — | | | | 16,567 | |
Stock options: | | | | | | | | | | | | | | | | | | | | |
Exercised | | | 18,470 | | | | — | | | | 13 | | | | — | | | | 13 | |
Repurchased and canceled | | | (2,495 | ) | | | — | | | | (150 | ) | | | — | | | | (150 | ) |
Restricted stock: | | | | | | | | | | | | | | | | | | | | |
Issued | | | 491,315 | | | | 5 | | | | — | | | | — | | | | 5 | |
Repurchased and canceled | | | (82,807 | ) | | | (1 | ) | | | (4,767 | ) | | | — | | | | (4,768 | ) |
Forfeited | | | (41,447 | ) | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2011 | | | 180,871,688 | | | $ | 1,809 | | | $ | 1,110,694 | | | $ | 1,195,623 | | | $ | 2,308,126 | |
|
| | | | | | | | | | | | | | | | | | | |
| In thousands, except share data | | Shares outstanding | | Common stock | | Additional paid-in capital | | Retained earnings | | Total shareholders’ equity |
| Balance at December 31, 2010 | | 170,408,652 |
| | $ | 1,704 |
| | $ | 439,900 |
| | $ | 766,551 |
| | $ | 1,208,155 |
|
| Net income | | — |
| | — |
| | — |
| | 429,072 |
| | 429,072 |
|
| Public offering of common stock | | 10,080,000 |
| | 101 |
| | 659,131 |
| | — |
| | 659,232 |
|
| Stock-based compensation | | — |
| | — |
| | 16,567 |
| | — |
| | 16,567 |
|
| Stock options: | | | | | | | | | | |
| Exercised | | 18,470 |
| | — |
| | 13 |
| | — |
| | 13 |
|
| Repurchased and canceled | | (2,495 | ) | | — |
| | (150 | ) | | — |
| | (150 | ) |
| Restricted stock: | | | | | | | | | | |
| Issued | | 491,315 |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Repurchased and canceled | | (82,807 | ) | | (1 | ) | | (4,767 | ) | | — |
| | (4,768 | ) |
| Forfeited | | (41,447 | ) | | — |
| | — |
| | — |
| | — |
|
| Balance at December 31, 2011 | | 180,871,688 |
| | $ | 1,809 |
| | $ | 1,110,694 |
| | $ | 1,195,623 |
| | $ | 2,308,126 |
|
| Net income | | — |
| | — |
| | — |
| | 739,385 |
| | 739,385 |
|
| Common stock issued in exchange for assets | | 3,916,157 |
| | 39 |
| | 81,489 |
| | — |
| | 81,528 |
|
| Stock-based compensation | | — |
| | — |
| | 30,209 |
| | — |
| | 30,209 |
|
| Excess tax benefit on stock-based compensation | | — |
| | — |
| | 15,618 |
| | — |
| | 15,618 |
|
| Stock options: | | | | | | | | | | |
| Exercised | | 86,500 |
| | — |
| | 60 |
| | — |
| | 60 |
|
| Repurchased and canceled | | (32,984 | ) | | — |
| | (2,951 | ) | | — |
| | (2,951 | ) |
| Restricted stock: | | | | | | | | | | |
| Issued | | 916,028 |
| | 9 |
| | — |
| | — |
| | 9 |
|
| Repurchased and canceled | | (112,521 | ) | | (1 | ) | | (8,284 | ) | | — |
| | (8,285 | ) |
| Forfeited | | (40,187 | ) | | — |
| | — |
| | — |
| | — |
|
| Balance at December 31, 2012 | | 185,604,681 |
| | $ | 1,856 |
| | $ | 1,226,835 |
| | $ | 1,935,008 |
| | $ | 3,163,699 |
|
| Net income | | — |
| | — |
| | — |
| | 764,219 |
| | 764,219 |
|
| Stock-based compensation | | — |
| | — |
| | 39,888 |
| | — |
| | 39,888 |
|
| Restricted stock: | | | | | | | | | | |
| Issued | | 261,259 |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Repurchased and canceled | | (138,525 | ) | | (1 | ) | | (14,689 | ) | | — |
| | (14,690 | ) |
| Forfeited | | (68,756 | ) | | (1 | ) | | — |
| | — |
| | (1 | ) |
| Balance at December 31, 2013 | | 185,658,659 |
| | $ | 1,857 |
| | $ | 1,252,034 |
| | $ | 2,699,227 |
| | $ | 3,953,118 |
|
The accompanying notes are an integral part of these consolidated financial statements.
71
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
| | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Cash flows from operating activities: | | | | | | | | | | | | |
Net income | | $ | 429,072 | | | $ | 168,255 | | | $ | 71,338 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
Depreciation, depletion, amortization and accretion | | | 391,844 | | | | 242,748 | | | | 208,885 | |
Property impairments | | | 108,458 | | | | 64,951 | | | | 83,694 | |
Change in fair value of derivatives | | | (4,057 | ) | | | 166,257 | | | | 2,089 | |
Stock-based compensation | | | 16,572 | | | | 11,691 | | | | 11,408 | |
Provision for deferred income taxes | | | 245,203 | | | | 77,359 | | | | 36,119 | |
Excess tax benefit from stock-based compensation | | | — | | | | (5,230 | ) | | | (2,872 | ) |
Dry hole costs | | | 7,949 | | | | 3,024 | | | | 6,477 | |
Gain on sale of assets, net | | | (20,838 | ) | | | (29,588 | ) | | | (709 | ) |
Other, net | | | 3,661 | | | | 4,366 | | | | 2,607 | |
Changes in assets and liabilities: | | | | | | | | | | | | |
Accounts receivable | | | (294,702 | ) | | | (299,480 | ) | | | 48,738 | |
Inventories | | | (3,412 | ) | | | (11,651 | ) | | | (4,501 | ) |
Prepaid expenses and other | | | (3,329 | ) | | | (2,398 | ) | | | 21,961 | |
Accounts payable trade | | | 83,907 | | | | 146,473 | | | | (117,643 | ) |
Revenues and royalties payable | | | 88,976 | | | | 66,262 | | | | (11,371 | ) |
Accrued liabilities and other | | | 20,784 | | | | 47,842 | | | | 13,842 | |
Other noncurrent assets and liabilities | | | (2,173 | ) | | | 2,286 | | | | 2,924 | |
| | | | | | | | | | | | |
Net cash provided by operating activities | | | 1,067,915 | | | | 653,167 | | | | 372,986 | |
Cash flows from investing activities: | | | | | | | | | | | | |
Exploration and development | | | (1,925,577 | ) | | | (1,031,499 | ) | | | (497,496 | ) |
Purchase of crude oil and natural gas properties | | | (65,315 | ) | | | (7,338 | ) | | | (1,217 | ) |
Purchase of other property and equipment | | | (44,750 | ) | | | (44,564 | ) | | | (8,257 | ) |
Proceeds from sale of assets | | | 30,928 | | | | 43,985 | | | | 7,148 | |
| | | | | | | | | | | | |
Net cash used in investing activities | | | (2,004,714 | ) | | | (1,039,416 | ) | | | (499,822 | ) |
Cash flows from financing activities: | | | | | | | | | | | | |
Revolving credit facility borrowings | | | 493,000 | | | | 341,000 | | | | 426,100 | |
Repayment of revolving credit facility | | | (165,000 | ) | | | (537,000 | ) | | | (576,500 | ) |
Proceeds from issuance of Senior Notes | | | — | | | | 587,210 | | | | 297,480 | |
Proceeds from issuance of common stock | | | 659,736 | | | | — | | | | — | |
Other debt | | | — | | | | — | | | | 3,304 | |
Repayment of other debt | | | — | | | | — | | | | (3,304 | ) |
Debt issuance costs | | | (36 | ) | | | (9,055 | ) | | | (10,028 | ) |
Equity issuance costs | | | (368 | ) | | | (136 | ) | | | — | |
Repurchase of equity grants | | | (4,918 | ) | | | (7,561 | ) | | | (4,299 | ) |
Excess tax benefit from stock-based compensation | | | — | | | | 5,230 | | | | 2,872 | |
Dividends to shareholders | | | — | | | | (2 | ) | | | (41 | ) |
Exercise of stock options | | | 13 | | | | 257 | | | | 245 | |
| | | | | | | | | | | | |
Net cash provided by financing activities | | | 982,427 | | | | 379,943 | | | | 135,829 | |
Net change in cash and cash equivalents | | | 45,628 | | | | (6,306 | ) | | | 8,993 | |
Cash and cash equivalents at beginning of period | | | 7,916 | | | | 14,222 | | | | 5,229 | |
| | | | | | | | | | | | |
Cash and cash equivalents at end of period | | $ | 53,544 | | | $ | 7,916 | | | $ | 14,222 | |
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Cash flows from operating activities: | | | | | | |
| Net income | | $ | 764,219 |
| | $ | 739,385 |
| | $ | 429,072 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
| Depreciation, depletion, amortization and accretion | | 965,437 |
| | 694,698 |
| | 391,844 |
|
| Property impairments | | 220,508 |
| | 122,274 |
| | 108,458 |
|
| Non-cash (gain) loss on derivatives, net | | 130,196 |
| | (199,737 | ) | | (4,057 | ) |
| Stock-based compensation | | 39,890 |
| | 29,057 |
| | 16,572 |
|
| Provision for deferred income taxes | | 442,621 |
| | 405,294 |
| | 245,203 |
|
| Excess tax benefit from stock-based compensation | | — |
| | (15,618 | ) | | — |
|
| Dry hole costs | | 9,350 |
| | 767 |
| | 7,949 |
|
| Gain on sale of assets, net | | (88 | ) | | (136,047 | ) | | (20,838 | ) |
| Other, net | | 2,037 |
| | 5,007 |
| | 3,661 |
|
| Changes in assets and liabilities: | | | | | | |
| Accounts receivable | | (166,138 | ) | | (91,791 | ) | | (294,702 | ) |
| Inventories | | (7,697 | ) | | (7,165 | ) | | (3,412 | ) |
| Prepaid expenses and other | | (11,537 | ) | | 14,381 |
| | (3,329 | ) |
| Accounts payable trade | | 107,250 |
| | (8,487 | ) | | 83,907 |
|
| Revenues and royalties payable | | 28,401 |
| | 40,030 |
| | 88,976 |
|
| Accrued liabilities and other | | 44,260 |
| | 40,309 |
| | 20,784 |
|
| Other noncurrent assets and liabilities | | (5,414 | ) | | (292 | ) | | (2,173 | ) |
| Net cash provided by operating activities | | 2,563,295 |
| | 1,632,065 |
| | 1,067,915 |
|
| | | | | | | |
| Cash flows from investing activities: | | | | | | |
| Exploration and development | | (3,660,773 | ) | | (3,493,652 | ) | | (1,925,577 | ) |
| Purchase of producing crude oil and natural gas properties | | (16,604 | ) | | (570,985 | ) | | (65,315 | ) |
| Purchase of other property and equipment | | (62,054 | ) | | (53,468 | ) | | (44,750 | ) |
| Proceeds from sale of assets and other | | 28,420 |
| | 214,735 |
| | 30,928 |
|
| Net cash used in investing activities | | (3,711,011 | ) | | (3,903,370 | ) | | (2,004,714 | ) |
| | | | | | | |
| Cash flows from financing activities: | | | | | | |
| Revolving credit facility borrowings | | 970,000 |
| | 2,119,000 |
| | 493,000 |
|
| Repayment of revolving credit facility | | (1,290,000 | ) | | (1,882,000 | ) | | (165,000 | ) |
| Proceeds from issuance of Senior Notes | | 1,479,375 |
| | 1,999,000 |
| | — |
|
| Proceeds from issuance of common stock | | — |
| | — |
| | 659,736 |
|
| Proceeds from other debt | | — |
| | 22,000 |
| | — |
|
| Repayment of other debt | | (1,951 | ) | | (1,579 | ) | | — |
|
| Debt issuance costs | | (2,265 | ) | | (7,373 | ) | | (36 | ) |
| Equity issuance costs | | — |
| | — |
| | (368 | ) |
| Repurchase of equity grants | | (14,690 | ) | | (11,236 | ) | | (4,918 | ) |
| Excess tax benefit from stock-based compensation | | — |
| | 15,618 |
| | — |
|
| Exercise of stock options | | — |
| | 60 |
| | 13 |
|
| Net cash provided by financing activities | | 1,140,469 |
| | 2,253,490 |
| | 982,427 |
|
| Net change in cash and cash equivalents | | (7,247 | ) | | (17,815 | ) | | 45,628 |
|
| Cash and cash equivalents at beginning of period | | 35,729 |
| | 53,544 |
| | 7,916 |
|
| Cash and cash equivalents at end of period | | $ | 28,482 |
| | $ | 35,729 |
| | $ | 53,544 |
|
The accompanying notes are an integral part of these consolidated financial statements.
72
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 1. Organization and Summary of Significant Accounting Policies
Description of the Company
Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company was originally formed in 1967 to explore for, develop and produceCompany's principal business is crude oil and natural gas properties. Continental’s operations areexploration, 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 riverRiver and includes North Dakota Bakken, Montana Bakken, and the Red River units and the Niobrara play in Colorado and Wyoming.units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi riverRiver including various plays in the Anadarko WoodfordSouth Central Oklahoma Oil Province (“SCOOP”), Northwest Cana and Arkoma Woodford plays inareas of Oklahoma. The East region contains propertiesis comprised of undeveloped leasehold acreage east of the Mississippi river includingRiver.
The Company’s operations are geographically concentrated in the Illinois BasinNorth region, with that region comprising approximately 77% of the Company’s crude oil and natural gas production and approximately 86% of its crude oil and natural gas revenues for the state of Michigan. Asyear ended December 31, 2013. Additionally, as of December 31, 2011,2013 approximately 71%76% of the Company’s estimated proved reserves were located in the North region. As
The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2013, crude oil accounted for approximately 71% of the Company’s total production and approximately 87% of its crude oil and natural gas revenues. Crude oil represents approximately 68% of the Company's estimated proved reserves as of December 31, 2011, the Company had interests in 3,255 wells and serves as the operator of 2,082, or 64%, of those wells.2013.
Basis of presentation
Continental has two wholly owned subsidiaries, Banner Pipeline Company, L.L.C., which currently has no assets or operations, and 20 Broadway Associates LLC, whose sole asset is an office building in Oklahoma City, Oklahoma where the Company is relocating its corporate headquarters in 2012. of consolidated financial statements
The consolidated financial statements include the accounts of
Continentalthe Company and its
whollysubsidiaries, all of which are 100% owned,
subsidiaries after all significant
inter-companyintercompany accounts and transactions have been
eliminated.eliminated upon consolidation.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure
and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results
couldmay 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
producingproved 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 consolidated financial statements.
Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred.
Each month the Company estimates the volumes sold and the price at which they were sold to record revenue. The following table shows the amounts of estimated crude oil and natural gas sales recorded as of December 31 for each indicated year. | | | | | | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | | | | In thousands | | | | |
Estimated crude oil and natural gas sales | | $ | 491,585 | | | $ | 263,075 | | | $ | 129,082 | |
Variances between estimated revenue and actual amounts received are recorded in the month payment is received and are included in the consolidated statements under the caption “Revenues—Crude Oil and Natural Gas Sales”. These variances have historically not been material. The Company uses the sales method of accounting for
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or liabilitypayable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 20112013 and 20102012 were not material.
Cash and cash equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2011,2013, the Company had cash deposits in excess of federally insured amounts of approximately $52.8 million.$28.0 million. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become
uncollectiblenoncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of
uncollectiblenoncollectable receivables have historically not been material.
Concentration of credit risk
The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant customers.purchasers. For the years ended December 31, 2011, 20102013, 2012 and 2009, crude oil2011, sales to one singlethe Company’s largest purchaser accounted for 41%approximately 15%, 57%21% and 56%41% of total revenues,crude oil and natural gas sales, respectively. Additionally, for the years ended December 31, 2013 and 2012 the Company’s second largest purchaser accounted for approximately 12% and 11%, respectively, of its total crude oil and natural gas sales. The Company's third largest purchaser accounted for approximately 11% of total crude oil and natural gas sales for the year ended December 31, 2013. No other purchaserpurchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for those three years.2011, 2012 and 2013. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in the Company’s operating regions.
Inventories are stated at the lower of cost or market and consist of the following:
| | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | |
| | | In thousands | |
Tubular goods and equipment | | $ | 15,665 | | | $ | 16,306 | |
Crude oil | | | 25,605 | | | | 22,056 | |
| | | | | | | | |
Total | | $ | 41,270 | | | $ | 38,362 | |
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
|
| | | | | | | | |
| | | December 31, |
| In thousands | | 2013 | | 2012 |
| Tubular goods and equipment | | $ | 11,139 |
| | $ | 13,590 |
|
| Crude oil | | 43,301 |
| | 33,153 |
|
| Total | | $ | 54,440 |
| | $ | 46,743 |
|
Crude oil inventories
including line fill, 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:
| | | | | | | | |
| | | December 31, | |
In barrels | | 2011 | | | 2010 | |
Crude oil line fill requirements | | | 283,000 | | | | 257,000 | |
Temporarily stored crude oil | | | 152,000 | | | | 148,000 | |
| | | | | | | | |
Total | | | 435,000 | | | | 405,000 | |
|
| | | | | | |
| | | December 31, |
| MBbls | | 2013 | | 2012 |
| Crude oil line fill requirements | | 370 |
| | 391 |
|
| Temporarily stored crude oil | | 344 |
| | 211 |
|
| Total | | 714 |
| | 602 |
|
Crude oil and natural gas properties
The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs
incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred.
Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the
costcosts of replacements or renewals that expand capacity or improve production are capitalized.
Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value. Total capitalized exploratory drilling costs pending the determination of proved reserves were $128.1$152.8 million and $92.8$92.7 million as of December 31, 20112013 and 2010,2012, respectively. As of December 31, 2011,2013, exploratory drilling costs of $6.5$3.9 million, representing 3 wells, were suspended one year beyond the completion of drilling and are expected to be fully evaluated in 2012.2014. Of the suspended costs, $5.2$0.5 million was incurred in 2010, $0.12013, $1.5 million was incurred in 2009, $1.12012, none in 2011 and $1.9 million was incurred in 20082010.
Continental Resources, Inc. and
the balance in 2007.Subsidiaries
Notes to Consolidated Financial Statements
Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, and materials and supplies utilized in the Company’s operations.
Service property and equipment
Service property and equipment consist primarily of furniture and fixtures, automobiles, machinery and equipment, office equipment, computer equipment and software, and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred.
Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows: | | |
| |
Service property and equipment | | Useful Lives
In Years | |
Furniture and fixtures | | | 10 |
| Automobiles | 5-6 |
Automobiles
| | | 5 | |
Machinery and equipment | | | 10-20 | |
Office equipment, computer equipment and software | | | 3-10 | |
Enterprise resource planning software | | | 25 | |
Buildings and improvements | | | 10-40 | |
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Depreciation, depletion and amortization
Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed crude oil and natural gas reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Asset retirement obligations
The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which
ita legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected
future abandonment
amountcost ratably over the related asset’s life.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company’s primary asset retirement obligations relate to future plugging and abandonment costs on its crude oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1,
20092011 through December 31,
2011: | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Asset retirement obligations at January 1 | | $ | 56,320 | | | $ | 50,167 | | | $ | 44,630 | |
Accretion expense | | | 3,163 | | | | 2,665 | | | | 2,250 | |
Revisions | | | 1,947 | | | | 2,564 | | | | 2,999 | |
Plus: Additions for new assets | | | 3,559 | | | | 2,794 | | | | 1,237 | |
Less: Plugging costs and sold assets | | | (2,364 | ) | | | (1,870 | ) | | | (949 | ) |
| | | | | | | | | | | | |
Total asset retirement obligations at December 31 | | $ | 62,625 | | | $ | 56,320 | | | $ | 50,167 | |
Less: Current portion of asset retirement obligations at December 31 | | | 2,287 | | | | 2,241 | | | | 2,460 | |
| | | | | | | | | | | | |
Non-current portion of asset retirement obligations at December 31 | | $ | 60,338 | | | $ | 54,079 | | | $ | 47,707 | |
2013:
|
| | | | | | | | | | | | |
| In thousands | | 2013 | | 2012 | | 2011 |
| Asset retirement obligations at January 1 | | $ | 47,171 |
| | $ | 62,625 |
| | $ | 56,320 |
|
| Accretion expense | | 2,767 |
| | 3,105 |
| | 3,163 |
|
| Revisions | | 2,826 |
| | (2,871 | ) | | 1,947 |
|
| Plus: Additions for new assets | | 6,009 |
| | 6,679 |
| | 3,559 |
|
| Less: Plugging costs and sold assets (1) | | (2,986 | ) | | (22,367 | ) | | (2,364 | ) |
| Total asset retirement obligations at December 31 | | $ | 55,787 |
| | $ | 47,171 |
| | $ | 62,625 |
|
| Less: Current portion of asset retirement obligations at December 31 (2) | | 1,434 |
| | 2,227 |
| | 2,287 |
|
| Non-current portion of asset retirement obligations at December 31 | | $ | 54,353 |
| | $ | 44,944 |
| | $ | 60,338 |
|
| |
| (1) | As a result of asset dispositions during the year ended December 31, 2012, the Company removed $20.0 million of its previously recognized asset retirement obligations that were assumed by the buyers. See Note 13. Property Acquisitions and Dispositions for further discussion. |
| |
| (2) | Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. |
As of December 31, 20112013 and 2010,2012, net property and equipment on the consolidated balance sheets included $43.8$44.4 million and $38.5$36.6 million, respectively, of net asset retirement costs.Impairment
Asset impairment
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
expectations for the future and includes 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.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Non-producing crude oil and natural gas properties
which primarily consist of undeveloped leasehold costs and costs associated with the purchase of
certain proved undeveloped
reserves,reserves. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis
for individually significant balances,and, if
any, and on an aggregate basis by prospect for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance
at the level consistent with the level at which impairment was assessed. For individually insignificant non-producing properties,
the amount of the impairment
losslosses are recognized
is determined by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the
lifelives of the
leaseleases based on experience of successful drilling and the average holding period. The
Company’s impairment
assessment isassessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Costs incurred in connection with the execution of the revolvingCompany’s credit facility and amendments thereto wereare capitalized and are being amortized over the term of the facility on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuance of the 81/ 1/4% Senior Notes due 2019, the 73/ 3/8% Senior Notes due 2020, and the 71/ 1/8% Senior Notes due 2021, the 5% Senior Notes due 2022 and the 4 1/2% Senior Notes due 2023 (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method. The Company had capitalized costs of $23.9$69.5 million and $27.2$55.3 million (net of accumulated amortization of $14.6$28.8 million and $11.3 million)$20.2 million) relating to its long-term debt at December 31, 20112013 and 2010,2012, respectively. DuringThe increase in 2013 resulted from the capitalization of costs incurred in connection with the Company’s April 2013 issuance of 4 1/2% Senior Notes due 2023 as discussed in Note 7. Long-Term Debt. For the years ended December 31, 2011, 20102013, 2012 and 2009,2011, the Company recognized associated amortization expense associated with capitalized debt issuance costs of $3.3$8.6 million $3.5, $5.6 million and $2.2$3.3 million, respectively, which are reflected in “Interest expense” onin the consolidated statements of income.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company
is required to recognizerecognizes its derivative instruments on the balance sheet as
either assets or liabilities
measured at fair value with such amounts classified as current or long-term based on
their anticipated settlement dates.
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 consolidated balance sheets. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the
realized and unrealized changechanges in fair value
on derivative instruments in the consolidated statements of
income.income under the caption “Gain (loss) on derivative instruments, net.”
Fair value of financial instruments
The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. The carrying valuevalues of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short term maturity of those instruments. The 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. See
Note 5. Derivative Instruments for quantification of the fair value of the Company’s derivative instruments at December 31, 2013 and 2012. Long-term debt consists of the Company’s Notes, its note payable, and borrowings on its credit facility. The fair values of the revolving credit facility and the Notes.Notes are based on quoted market prices. The fair value of the revolvingnote 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 credit facility borrowings approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The estimatedSee Note 6. Fair Value Measurements for quantification of the fair value of outstanding revolving credit facility borrowings was $358.0 million and $30.0 millionthe Company’s long-term debt obligations at December 31, 20112013 and 2010, respectively. The fair values of the Notes are based on quoted market prices and totaled $985.3 million at December 31, 2011 and $963.8 million at December 31, 2010.Continental Resources, Inc. and Subsidiaries2012.
Notes to Consolidated Financial Statements
Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between
the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense.
Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards and dilutive stock options, which are calculated using the treasury stock method as if the awards and options were exercised. The following istable presents the calculation of basic and diluted weighted average shares outstanding and net income per share for the years ended December 31, 2013, 2012 and 2011. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012.
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands, except per share data | | 2013 | | 2012 | | 2011 |
| Income (numerator): | | | | | | |
| Net income - basic and diluted | | $ | 764,219 |
| | $ | 739,385 |
| | $ | 429,072 |
|
| Weighted average shares (denominator): | | | | | | |
| Weighted average shares - basic | | 184,075 |
| | 181,340 |
| | 177,590 |
|
| Non-vested restricted stock | | 774 |
| | 490 |
| | 544 |
|
| Stock options | | — |
| | 16 |
| | 96 |
|
| Weighted average shares - diluted | | 184,849 |
| | 181,846 |
| | 178,230 |
|
| Net income per share: | | | | | | |
| Basic | | $ | 4.15 |
| | $ | 4.08 |
| | $ | 2.42 |
|
| Diluted | | $ | 4.13 |
| | $ | 4.07 |
| | $ | 2.41 |
|
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Adoption of new accounting standard
In December 2011, 2010the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance Sheet (Topic 210)–Disclosures about Offsetting Assets and 2009: | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands, except per share data | |
Income (numerator): | | | | | | | | | | | | |
Net income - basic and diluted | | $ | 429,072 | | | $ | 168,255 | | | $ | 71,338 | |
Weighted average shares (denominator): | | | | | | | | | | | | |
Weighted average shares - basic | | | 177,590 | | | | 168,985 | | | | 168,559 | |
Non-vested restricted stock | | | 544 | | | | 546 | | | | 562 | |
Employee stock options | | | 96 | | | | 248 | | | | 408 | |
| | | | | | | | | | | | |
Weighted average shares - diluted | | | 178,230 | | | | 169,779 | | | | 169,529 | |
Net income per share: | | | | | | | | | | | | |
Basic | | $ | 2.42 | | | $ | 1.00 | | | $ | 0.42 | |
Diluted | | $ | 2.41 | | | $ | 0.99 | | | $ | 0.42 | |
Note 2. 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.
| | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Supplemental cash flow information: | | | | | | | | | | | | |
Cash paid for interest | | $ | 70,088 | | | $ | 36,845 | | | $ | 14,562 | |
Cash paid for income taxes | | $ | 16,030 | | | $ | 10,879 | | | $ | 146 | |
Cash received for income tax refunds | | $ | (116 | ) | | $ | (1,406 | ) | | $ | (22,040 | ) |
Non-cash investing activities: | | | | | | | | | | | | |
Asset retirement obligations, net | | $ | 5,506 | | | $ | 5,358 | | | $ | 4,236 | |
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Supplemental cash flow information: | | | | | | |
| Cash paid for interest | | $ | 209,815 |
| | $ | 102,043 |
| | $ | 70,088 |
|
| Cash paid for income taxes | | 29,017 |
| | 829 |
| | 16,030 |
|
| Cash received for income tax refunds | | (174 | ) | | (13,866 | ) | | (116 | ) |
| Non-cash investing activities: | | | | | | |
| Increase in accrued capital expenditures | | 89,482 |
| | 49,039 |
| | 173,591 |
|
| Acquisition of assets through issuance of common stock (Note 14) | | — |
| | 176,563 |
| | — |
|
| Asset retirement obligation additions and revisions, net | | 8,835 |
| | 3,808 |
| | 5,506 |
|
Note 3. Net Property and Equipment
Net property and equipment includes the following at December 31,
20112013 and
2010: | | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | |
| | | In thousands | |
Proved crude oil and natural gas properties | | $ | 5,376,109 | | | $ | 3,431,628 | |
Unproved crude oil and natural gas properties | | | 663,493 | | | | 547,077 | |
Service properties, equipment and other | | | 124,357 | | | | 80,337 | |
| | | | | | | | |
Total property and equipment | | | 6,163,959 | | | | 4,059,042 | |
Accumulated depreciation, depletion and amortization | | | (1,482,226 | ) | | | (1,077,051 | ) |
| | | | | | | | |
Net property and equipment | | $ | 4,681,733 | | | $ | 2,981,991 | |
|
| | | | | | | | |
| | | | December 31, |
| In thousands | | | 2013 | | | 2012 |
| Proved crude oil and natural gas properties | | $ | 12,423,878 |
| | $ | 8,980,505 |
|
| Unproved crude oil and natural gas properties | | | 1,181,268 |
| | | 1,073,944 |
|
| Service properties, equipment and other | | | 236,233 |
| | | 170,763 |
|
| Total property and equipment | | | 13,841,379 |
| | | 10,225,212 |
|
| Accumulated depreciation, depletion and amortization | | | (3,120,107 | ) | | | (2,119,943 | ) |
| Net property and equipment | | $ | 10,721,272 |
| | $ | 8,105,269 |
|
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 4. Accrued Liabilities and Other
Accrued liabilities and other includes the following at December 31,
20112013 and
2010: | | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | |
| | | In thousands | |
Prepaid advances from joint interest owners | | $ | 52,798 | | | $ | 47,710 | |
Accrued compensation | | | 14,449 | | | | 8,434 | |
Accrued production taxes and ad valorem taxes | | | 30,208 | | | | 18,649 | |
Accrued interest | | | 16,922 | | | | 18,140 | |
Other | | | 3,297 | | | | 1,896 | |
| | | | | | | | |
Accrued liabilities and other | | $ | 117,674 | | | $ | 94,829 | |
|
| | | | | | | | |
| | | | December 31, |
| In thousands | | | 2013 | | | 2012 |
| Prepaid advances from joint interest owners | | $ | 57,196 |
| | $ | 30,434 |
|
| Accrued compensation | | | 41,757 |
| | | 27,797 |
|
| Accrued production taxes, ad valorem taxes and other non-income taxes | | | 35,900 |
| | | 33,466 |
|
| Accrued income taxes | | | — |
| | | 10,455 |
|
| Accrued interest | | | 61,216 |
| | | 46,973 |
|
| Current portion of asset retirement obligations | | | 1,434 |
| | | 2,227 |
|
| Other | | | 610 |
| | | 4,329 |
|
| Accrued liabilities and other | | $ | 198,113 |
| | $ | 155,681 |
|
Note 5. Derivative Instruments
The Company
is required to recognizerecognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the
realized and unrealized changes in fair value in the consolidated statements of income under the caption
“Loss“Gain (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.
During the year ended December 31, 2011, the Company entered into several new swap and collar derivative contracts covering a portion of its crude oil and natural gas production for 2011, 2012 and 2013. The new contracts were entered into in the ordinary course of business and the Company may enter into additional similar contracts in the future. None of the Company’s contracts have been designated for hedge accounting.
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
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
basis swap contract, which guarantees a price differential between the NYMEX prices and the Company’s physical pricing points, the Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and the Company pays the counterparty if the settled price differential is less than the stated terms of the contract. 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.
All of the Company’sThe Company's derivative contracts are carried at their fair value on the 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 and subject to contractual terms which provide for net settlement are reported on a net basis on the consolidated balance sheets. Derivative instruments existing at December 31, 2011 are settled based upon reported settlement prices on the NYMEX,commodity exchanges, with crude oil derivatives being tied toderivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing or Inter-Continental Exchange ("ICE") pricing for Brent crude oil and natural gas derivatives being tied toderivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of thesederivative contracts is based upon various factors, including closingcommodity exchange prices, on the NYMEX, 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. SeeNote 6. Fair Value Measurements.At December 31, 2011,2013, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude Oil –West Texas Intermediate | | Bbls | | | Swaps
Weighted
Average | | | Collars | |
| | | | | Floors | | | Ceilings | |
Period and Type of Contract | | | | Range | | | Weighted
Average | | | Range | | | Weighted
Average | |
| | | | | | |
January 2012 - December 2012 | | | | | | | | | | | | | | | | | | | | | | | | |
Swaps | | | 7,320,000 | | | $ | 88.69 | | | | | | | | | | | | | | | | | |
Collars | | | 5,332,620 | | | | | | | $ | 80.00 | | | $ | 80.00 | | | $ | 93.25-$97.00 | | | $ | 94.71 | |
January 2013- December 2013 | | | | | | | | | | | | | | | | | | | | | | | | |
Swaps | | | 5,110,000 | | | $ | 88.63 | | | | | | | | | | | | | | | | | |
Collars | | | 8,760,000 | | | | | | | $ | 80.00-$95.00 | | | $ | 86.92 | | | $ | 92.30-$110.33 | | | $ | 99.46 | |
| | | | | | |
| Natural Gas –Henry Hub | | | | | Swaps
Weighted
Average | | | | | | | | | | | | | |
| | | MMBtus | | | | | | | | | | | | | | |
Period and Type of Contract | | | | | | | | |
January 2012 - December 2012 | | | | | | | | | | | | | | | | | | | | | | | | |
Swaps | | | 3,660,000 | | | $ | 5.07 | | | | | | | | | | | | | | | | | |
|
| | | | | | | |
| Crude Oil–NYMEX WTI | | | | Swaps Weighted Average Price |
| Period and Type of Contract | | Bbls |
| January 2014 - December 2014 | | | | |
| Swaps - WTI | | 10,851,250 |
| | $ | 96.50 |
|
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | Swaps Weighted Average Price | | Collars |
| Crude Oil–ICE Brent | | Bbls | | Floors | | Ceilings |
| Period and Type of Contract | | Range | | Weighted Average Price | | Range | | Weighted Average Price |
| January 2014 - December 2014 | | | | | | | | | | | | |
| Swaps - ICE Brent | | 17,028,000 |
| | $ | 103.17 |
| | | | | | | | |
| Collars - ICE Brent | | 2,190,000 |
| | | | $90.00 - $95.00 |
| | $ | 90.83 |
| | $104.70 - $108.85 |
| | $ | 107.13 |
|
| January 2015 - December 2015 | | | | | | | | | | | | |
| Swaps - ICE Brent | | 2,737,500 |
| | $ | 99.15 |
| | | | | | | | |
| Collars - ICE Brent | | 730,000 |
| |
|
| | $ | 95.00 |
| | $ | 95.00 |
| | $ | 107.40 |
| | $ | 107.40 |
|
|
| | | | | | | |
| Natural Gas–NYMEX Henry Hub | | MMBtus | | Swaps Weighted Average Price |
| | |
| Period and Type of Contract | |
| January 2014 - December 2014 | | | | |
| Swaps - Henry Hub | | 64,250,000 |
| | $ | 4.19 |
|
| January 2015 - March 2015 | | | | |
| Swaps - Henry Hub | | 1,800,000 |
| | $ | 4.27 |
|
Derivative
Fair Value Gain (Loss)gains and losses
The following table presents
realizedcash settlements on matured derivative instruments and
unrealizednon-cash gains and losses on
open derivative instruments for the periods presented.
| | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Realized gain (loss) on derivatives: | | | | | | | | | | | | |
Crude oil fixed price swaps | | $ | (14,900 | ) | | $ | 11,386 | | | $ | — | |
Crude oil collars | | | (56,511 | ) | | | 1,809 | | | | — | |
Natural gas fixed price swaps | | | 37,305 | | | | 25,246 | | | | 569 | |
Natural gas basis swaps | | | — | | | | (2,946 | ) | | | — | |
| | | | | | | | | | | | |
Total realized gain (loss) on derivatives | | $ | (34,106 | ) | | $ | 35,495 | | | $ | 569 | |
Unrealized gain (loss) on derivatives: | | | | | | | | | | | | |
Crude oil fixed price swaps | | $ | (23,486 | ) | | $ | (85,870 | ) | | $ | (423 | ) |
Crude oil collars | | | 42,239 | | | | (100,143 | ) | | | (3,275 | ) |
Natural gas fixed price swaps | | | (14,696 | ) | | | 17,161 | | | | 4,204 | |
Natural gas basis swaps | | | — | | | | 2,595 | | | | (2,595 | ) |
| | | | | | | | | | | | |
Total unrealized gain (loss) on derivatives | | $ | 4,057 | | | $ | (166,257 | ) | | $ | (2,089 | ) |
| | | | | | | | | | | | |
Loss on derivative instruments, net | | $ | (30,049 | ) | | $ | (130,762 | ) | | $ | (1,520 | ) |
The table Cash receipts and payments below provides data aboutreflect 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 derivativesderivative 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.
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 |
| 2012 |
| 2011 |
| Cash received (paid) on derivatives: | | | | | | |
| Crude oil fixed price swaps | | $ | (54,289 | ) | | $ | (40,238 | ) | | $ | (14,900 | ) |
| Crude oil collars | | (16,867 | ) | | (15,341 | ) | | (56,511 | ) |
| Natural gas fixed price swaps | | 9,601 |
| | 9,858 |
| | 37,305 |
|
| Cash paid on derivatives, net | | $ | (61,555 | ) | | $ | (45,721 | ) | | $ | (34,106 | ) |
| Non-cash gain (loss) on derivatives: | | | | | | |
| Crude oil fixed price swaps | | $ | (117,580 | ) | | $ | 142,567 |
| | $ | (23,486 | ) |
| Crude oil collars | | (8,587 | ) | | 59,911 |
| | 42,239 |
|
| Natural gas fixed price swaps | | (4,029 | ) | | (2,741 | ) | | (14,696 | ) |
| Non-cash gain (loss) on derivatives, net | | $ | (130,196 | ) | | $ | 199,737 |
| | $ | 4,057 |
|
| Gain (loss) on derivative instruments, net | | $ | (191,751 | ) | | $ | 154,016 |
| | $ | (30,049 | ) |
Balance sheet offsetting of derivative assets and liabilities
In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)-Disclosures about Offsetting Assets and Liabilities, which requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity's financial position. The Company adopted the provisions of the new standard on January 1, 2013 as required and has provided the applicable disclosures below with respect to its derivative instruments.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
All of the Company’s derivative contracts are carried at their fair value in the 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
not accountedsubject to contractual terms which provide for
using hedge accounting. | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2011 | | | December 31, 2010 | |
| | | Assets | | | (Liabilities) | | | Net | | | Assets | | | (Liabilities) | | | Net | |
In thousands | | Fair
Value | | | Fair
Value | | | Fair
Value | | | Fair
Value | | | Fair
Value | | | Fair
Value | |
Commodity swaps and collars | | $ | 10,294 | | | $ | (174,583 | ) | | $ | (164,289 | ) | | $ | 21,365 | | | $ | (189,711 | ) | | $ | (168,346 | ) |
The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2013 | | December 31, 2012 |
| In thousands | | Gross
amounts of
recognized
assets | | Gross amounts
offset on
balance sheet | | Net amounts of
assets on
balance sheet | | Gross
amounts of
recognized
assets | | Gross amounts
offset on
balance sheet | | Net amounts of
assets on
balance sheet |
| Commodity derivative assets | | $ | 4,213 |
| | $ | (597 | ) | | $ | 3,616 |
| | $ | 86,506 |
| | $ | (35,886 | ) | | $ | 50,620 |
|
| | | | | | | | | | | | | |
| | | December 31, 2013 | | December 31, 2012 |
| In thousands | | Gross
amounts of
recognized
liabilities | | Gross amounts
offset on
balance sheet | | Net amounts of
liabilities on
balance sheet | | Gross
amounts of
recognized
liabilities | | Gross amounts
offset on
balance sheet | | Net amounts of
liabilities on
balance sheet |
| Commodity derivative liabilities | | $ | (125,709 | ) | | $ | 27,345 |
| | $ | (98,364 | ) | | $ | (16,241 | ) | | $ | 1,069 |
| | $ | (15,172 | ) |
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets.
|
| | | | | | | | |
| In thousands | | December 31, 2013 | | December 31, 2012 |
| Derivative assets | | $ | 3,616 |
| | $ | 18,389 |
|
| Noncurrent derivative assets | | — |
| | 32,231 |
|
| Net amounts of assets on balance sheet | | 3,616 |
| | 50,620 |
|
| Derivative liabilities | | (90,535 | ) | | (12,999 | ) |
| Noncurrent derivative liabilities | | (7,829 | ) | | (2,173 | ) |
| Net amounts of liabilities on balance sheet | | (98,364 | ) | | (15,172 | ) |
| Total derivative assets (liabilities), net | | $ | (94,748 | ) | | $ | 35,448 |
|
Note 6. Fair Value Measurements
The Company follows
Accounting Standards Codification Topic 820,Fair Value Measurements and Disclosures, which establishes 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
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available.
The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Assets and
Liabilities Measuredliabilities measured at
Fair Valuefair value on a
Recurring BasisCertain assets and liabilitiesrecurring basis
The Company's derivative instruments are reported at fair value on a recurring
basis, including the Company’s derivative instruments.basis. In determining the fair values of fixed price
swaps and basis 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
observable inputs relating to basis differentials and a risk-adjusted discount rate. The fair values of fixed price
swaps and basis swaps are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collar contracts requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation
of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.
The following
table summarizestables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31,
20112013 and
2010. | | | | | | | | | | | | | | | | |
| | | Fair value measurements at December 31, 2011 using: | | | | |
Description | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | | | | In thousands | | | | | | | |
Derivative assets (liabilities): | | | | | | | | | | | | | | | | |
Fixed price swaps | | $ | — | | | $ | (103,110 | ) | | $ | — | | | $ | (103,110 | ) |
Collars | | | — | | | | (61,179 | ) | | | — | | | | (61,179 | ) |
| | | | | | | | | | | | | | | | |
Total | | $ | — | | | $ | (164,289 | ) | | $ | — | | | $ | (164,289 | ) |
| | |
| | | Fair value measurements at December 31, 2010 using: | | | | |
Description | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | | | | In thousands | | | | | | | |
Derivative assets (liabilities): | | | | | | | | | | | | | | | | |
Fixed price swaps | | $ | — | | | $ | (64,928 | ) | | $ | — | | | $ | (64,928 | ) |
Collars | | | — | | | | — | | | | (103,418 | ) | | | (103,418 | ) |
| | | | | | | | | | | | | | | | |
Total | | $ | — | | | $ | (64,928 | ) | | $ | (103,418 | ) | | $ | (168,346 | ) |
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following table sets forth a reconciliation of changes in the2012.
|
| | | | | | | | | | | | | | | | |
| In thousands | | Fair value measurements at December 31, 2013 using: | | |
| Description | | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative assets (liabilities): | | |
| Fixed price swaps | | $ | — |
| | $ | (84,893 | ) | | $ | — |
| | $ | (84,893 | ) |
| Collars | | — |
| | (9,855 | ) | | — |
| | (9,855 | ) |
| Total | | $ | — |
| | $ | (94,748 | ) | | $ | — |
| | $ | (94,748 | ) |
|
| | | | | | | | | | | | | | | | |
| In thousands | | Fair value measurements at December 31, 2012 using: | | |
|
| Description | | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative assets (liabilities): | | |
| Fixed price swaps | | $ | — |
| | $ | 36,716 |
| | $ | — |
| | $ | 36,716 |
|
| Collars | | — |
| | (1,268 | ) | | — |
| | (1,268 | ) |
| Total | | $ | — |
| | $ | 35,448 |
| | $ | — |
| | $ | 35,448 |
|
Assets measured at fair value
of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods. Transfers out of Level 3 during the year ended December 31, 2011 were attributable to the Company’s ability to corroborate the volatility factors used to value its collar contracts with observable changes in forward commodity prices, which resulted in the Company transferring its collar contracts from Level 3 to Level 2 during the third quarter of 2011. 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. | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Balance at January 1 | | $ | (103,418 | ) | | $ | (3,275 | ) | | $ | — | |
Total realized or unrealized gains (losses), net: | | | | | | | | | | | | |
Included in earnings | | | (47,515 | ) | | | (100,143 | ) | | | (3,275 | ) |
Included in other comprehensive income | | | — | | | | — | | | | — | |
Purchases | | | — | | | | — | | | | — | |
Sales | | | — | | | | — | | | | — | |
Issuances | | | — | | | | — | | | | — | |
Settlements | | | — | | | | — | | | | — | |
Transfers into Level 3 | | | — | | | | — | | | | — | |
Transfers out of Level 3 | | | 150,933 | | | | — | | | | — | |
| | | | | | | | | | | | |
Balance at December 31 | | $ | — | | | $ | (103,418 | ) | | $ | (3,275 | ) |
Unrealized gains (losses) relating to derivatives still held at December 31 | | $ | — | | | $ | (99,110 | ) | | $ | (3,275 | ) |
Gains and losses included in earnings for the years ended December 31, 2011 and 2010 attributable to the change in unrealized gains and losses relating to derivatives held at December 31, 2011 and 2010 are reported in the consolidated statements of income under the caption “Loss on derivative instruments, net”.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
nonrecurring basis
Certain assets
and liabilities are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those
assets and liabilities.assets.
Asset Impairmentsimpairments – 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).Non-producing 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 whichusing 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% |
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
Impairments of proved properties amounted to $51.8 million for the year ended December 31, 2013. Such impairments primarily consistreflected fair value adjustments made for certain properties in the Niobrara play in Colorado and Wyoming driven by uneconomic well results. The impaired properties were written down to their estimated fair value totaling approximately $21.2 million.
Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2013 and 2012, primarily reflecting recurring amortization of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves, are assessed for impairment on a property-by-property basis for individually significant balances, if any, and on an aggregate basis by prospect for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level consistent with the level at which impairment was assessed. For individuallyContinental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
insignificant non-producing properties the amount of the impairment loss recognized is determined by amortizing the portion of the properties’ costs whichthat management estimatesexpects will not be transferred to proved properties over the lifelives of the leaseleases based on experience of successful drilling and the average holding period. TheAdditionally, undeveloped leasehold costs on certain properties in the Niobrara play were individually assessed for impairment assessment is affected by economic factors such asin the results2013 fourth quarter based on indicators of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms,impairment and potential shifts in business strategy employed by management. Thewere written down to fair value of non-producing properties is calculated using significant unobservable inputs (Level 3).
As a result$14.9 million, which resulted in $8.4 million of changesimpairment charges being recognized in reserves andaddition to the commodity futures price strips, proved properties were reviewed for impairment at December 31, 2011. 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 $16.1 million for the year ended December 31, 2011. Further, certain non-producing properties were impaired during the year ended December 31, 2011, reflectingrecurring amortization of undeveloped leasehold costs. described above.
The following table sets forth the
pre-tax non-cash impairments of both proved and
non-producingunproved properties for the indicated periods. Proved and
non-producingunproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of income.
| | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Proved property impairments | | $ | 16,107 | | | $ | 1,681 | | | $ | 36,607 | |
Non-producing property impairments | | | 92,351 | | | | 63,270 | | | | 47,087 | |
| | | | | | | | | | | | |
Total | | $ | 108,458 | | | $ | 64,951 | | | $ | 83,694 | |
Asset Retirement Obligations – The
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Proved property impairments | | $ | 51,805 |
| | $ | 4,332 |
| | $ | 16,107 |
|
| Unproved property impairments | | 168,703 |
| | 117,942 |
| | 92,351 |
|
| Total | | $ | 220,508 |
| | $ | 122,274 |
| | $ | 108,458 |
|
Financial instruments not recorded at fair value
of asset retirement obligations (AROs) is estimated based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, the credit-adjusted risk-free rate to be used, and inflation rates. The fair values of ARO additions for the years ended December 31, 2011 and 2010 were $3.6 million and $2.8 million, respectively, which are reflected under the caption “Asset retirement obligations, net of current portion” in the consolidated balance sheets. The fair values of AROs are calculated using significant unobservable inputs (Level 3).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 consolidated financial statements.
| | | | | | | | | | | | | | | | |
| | | December 31, 2011 | | | December 31, 2010 | |
| | | Carrying
Amount | | | | | | Carrying
Amount | | | | |
| | | | Fair Value | | | | Fair Value | |
| | | In thousands | |
Long-term debt | | | | | | | | | | | | | | | | |
Revolving credit facility | | $ | 358,000 | | | $ | 358,000 | | | $ | 30,000 | | | $ | 30,000 | |
8 1/4% Senior Notes due 2019 | | | 297,882 | | | | 331,000 | | | | 297,696 | | | | 331,500 | |
7 3/8% Senior Notes due 2020 | | | 198,419 | | | | 219,000 | | | | 198,295 | | | | 213,000 | |
7 1/8% Senior Notes due 2021 | | | 400,000 | | | | 435,333 | | | | 400,000 | | | | 419,333 | |
| | | | | | | | | | | | | | | | |
Total | | $ | 1,254,301 | | | $ | 1,343,333 | | | $ | 925,991 | | | $ | 993,833 | |
|
| | | | | | | | | | | | | | | | |
| | | December 31, 2013 | | December 31, 2012 |
| In thousands | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Debt: | | | | | | | | |
| Credit facility | | $ | 275,000 |
| | $ | 275,000 |
| | $ | 595,000 |
| | $ | 595,000 |
|
| Note payable | | 18,470 |
| | 16,500 |
| | 20,421 |
| | 20,148 |
|
| 8 1/4% Senior Notes due 2019 | | 298,305 |
| | 327,800 |
| | 298,085 |
| | 339,000 |
|
| 7 3/8% Senior Notes due 2020 | | 198,695 |
| | 223,700 |
| | 198,552 |
| | 226,833 |
|
| 7 1/8% Senior Notes due 2021 | | 400,000 |
| | 450,300 |
| | 400,000 |
| | 454,333 |
|
| 5% Senior Notes due 2022 | | 2,025,362 |
| | 2,063,300 |
| | 2,027,663 |
| | 2,165,833 |
|
| 4 1/2% Senior Notes due 2023 | | 1,500,000 |
| | 1,519,400 |
| | — |
| | — |
|
| Total debt | | $ | 4,715,832 |
| | $ | 4,876,000 |
| | $ | 3,539,721 |
| | $ | 3,801,147 |
|
The fair value of the revolving credit facility borrowings approximates its carrying value based on the borrowing rates available to the Company for bank loans with similar terms and maturities. 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/ 1/4% Senior Notes due 2019 (“2019 Notes”), the 73/ 3/8% Senior Notes due 2020 and(“2020 Notes”), the 71/ 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 (Level 1).and, accordingly, are classified as Level 1 in the fair value hierarchy.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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.
Long-term debt consists of the
following: | | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | |
| | | In thousands | |
Revolving credit facility | | $ | 358,000 | | | $ | 30,000 | |
8 1/4% Senior Notes due 2019(1) | | | 297,882 | | | | 297,696 | |
7 3/8% Senior Notes due 2020(2) | | | 198,419 | | | | 198,295 | |
7 1/8% Senior Notes due 2021(3) | | | 400,000 | | | | 400,000 | |
| | | | | | | | |
Total long-term debt | | $ | 1,254,301 | | | $ | 925,991 | |
|
| | | | | | | | |
| | | December 31, |
| In thousands | | 2013 | | 2012 |
| Credit facility | | $ | 275,000 |
| | $ | 595,000 |
|
| Note payable | | 18,470 |
| | 20,421 |
|
| 8 1/4% Senior Notes due 2019 (1) | | 298,305 |
| | 298,085 |
|
| 7 3/8% Senior Notes due 2020 (2) | | 198,695 |
| | 198,552 |
|
| 7 1/8% Senior Notes due 2021 (3) | | 400,000 |
| | 400,000 |
|
| 5% Senior Notes due 2022 (4) | | 2,025,362 |
| | 2,027,663 |
|
| 4 1/2% Senior Notes due 2023 (3) | | 1,500,000 |
| | — |
|
| Total debt | | 4,715,832 |
| | 3,539,721 |
|
| Less: Current portion of long-term debt | | (2,011 | ) | | (1,950 | ) |
| Long-term debt, net of current portion | | $ | 4,713,821 |
| | $ | 3,537,771 |
|
| |
| (1) | The carrying amount is net of unamortized discounts of $2.1$1.7 million and $2.3$1.9 million at December 31, 20112013 and 2010,2012, respectively. |
| |
| (2) | The carrying amount is net of unamortized discounts of $1.6$1.3 million and $1.7$1.4 million at December 31, 20112013 and 2010,2012, respectively. |
| |
| (3) | TheThese notes were sold at par and are recorded at 100% of face value. |
Revolving | |
| (4) | The carrying amount includes an unamortized premium of $25.4 million and $27.7 million at December 31, 2013 and 2012, respectively. |
Credit facility
The Company has a credit facility,
maturing on July 1, 2015, with aggregate lender commitments totaling $1.5 billion, which can be increased up to $2.5 billion under the terms of the facility. In November 2013, following an upgrade by Standard & Poor’s Rating Services (“S&P”), as permitted by the credit facility terms, the Company provided the lenders under its credit facility notice of its intention to elect an Additional Covenant Period (as defined in the credit facility). The election of an Additional Covenant Period means that the credit facility is not currently subject to a borrowing base. The election was made in order to facilitate the release of collateral consisting of oil and gas properties securing obligations under the credit facility. On December 11, 2013, the Company delivered notice to the credit facility lenders confirming it had satisfied all conditions for releasing the collateral and the release of such collateral became effective as of December 12, 2013. On December 13, 2013, the Company's credit rating was upgraded by Moody's Investor Services, Inc (“Moody’s”). As a result of the second upgrade, the Company is not currently required to: (i) comply with certain reporting requirements; and (ii) maintain a ratio of the present value of oil and gas properties to total funded debt of not less than 1.5 to 1.0, as set forth in the credit facility.
The Company had $358.0$275 million of outstanding borrowings at December 31, 2011 on its credit facility, which matures on July 1, 2015. At December 31, 2010, the Company had $30.0 and $595 million of outstanding borrowings on its credit facility. The credit facility had aggregate commitments of $750.0 million and a borrowing base of $2.25 billion at December 31, 2011, subject to semi-annual redetermination. The most recent borrowing base redetermination was completed in October 2011, whereby the lenders approved an increase in the Company’s borrowing base from $2.0 billion to $2.25 billion. The terms of the facility provide that the commitment level can be increased up to the lesser of the borrowing base then in effect or $2.5 billion. Subsequent to December 31, 2011, the Company requested,2013 and was granted by the lenders, an increase in the aggregate credit facility commitments from $750.0 million to $1.25 billion, effective January 31, 2012. The borrowing base of $2.25 billion and all other substantive terms of the credit facility remained unchanged.2012, respectively. Borrowings under the facility at December 31, 2013 bear interest payable quarterly, at a rate per annum equal to the London Interbank Offered Rate (LIBOR) for one, two, three or six months, as elected by the Company, plus a margin ranging from 175 to 275of 150 basis points, depending on the percentage of the borrowing base utilized, or the lead bank’s reference rate (prime) plus a margin ranging from 75 to 17550 basis points. Borrowings are secured by the Company’s interest in at least 85% (by value) of all of its proved reserves and associated crude oil and natural gas properties. The Company had $389.2 millionapproximately $1.2 billion of unused commitments (after considering outstanding borrowings and letters of credit) under its credit facility at December 31, 20112013 and incurs commitment fees of 0.50%0.25% per annum of the daily average amount of unused borrowing availability. The credit agreement 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 3.754.0 to 1.0. As defined by the credit agreement,facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available borrowing capacity under the credit agreementfacility 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, unrealized derivativenon-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cashContinental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. A reconciliation of net income to EBITDAX is provided inPart II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures. The total funded debt to EBITDAX
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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
allthese covenants at December 31,
2011.2013.
In April 2013, the Company issued $1.5 billion of 4 1/4%2% Senior Notes due 2019 (the “2019 Notes”),2023 and received net proceeds of approximately $1.48 billion after deducting the 7 3/8% Senior Notes due 2020 (the “2020 Notes”), and the 7 1/8% Senior Notes due 2021 (the “2021 Notes”) will mature on October 1, 2019, October 1, 2020, and April 1, 2021, respectively. Interest on the Notes is payable semi-annually on April 1 and October 1 of each year, with the payment of interest on the 2021 Notes having commenced on April 1, 2011.initial purchasers' fees. The Company hasused the optionnet proceeds from the offering to redeemrepay all orborrowings then outstanding under its credit facility, which had a balance prior to payoff of approximately $1.04 billion, to fund a portion of its 2013 capital budget, and for general corporate purposes.
The following table summarizes the 2019 Notes, 2020 Notes,maturity dates, semi-annual interest payment dates, and 2021 Notes at any time on or after October 1, 2014, October 1, 2015, and April 1, 2016, respectively, atoptional redemption periods related to the redemption prices specified in the Notes’ respective indentures (together, the “Indentures”) plus accrued and unpaid interest. Company’s outstanding senior note obligations.
|
| | | | | | | | | | |
| | 2019 Notes | | 2020 Notes | | 2021 Notes | | 2022 Notes | | 2023 Notes |
| Maturity date | | Oct 1, 2019 | | Oct 1, 2020 | | April 1, 2021 | | Sep 15, 2022 | | April 15, 2023 |
| Interest payment dates | | April 1, Oct. 1 | | April 1, Oct. 1 | | April 1, Oct. 1 | | March 15, Sept. 15 | | April 15, Oct. 15 |
| Call premium redemption period (1) | | Oct 1, 2014 | | Oct 1, 2015 | | April 1, 2016 | | March 15, 2017 | | n/a |
| Make-whole redemption period (2) | | Oct 1, 2014 | | Oct 1, 2015 | | April 1, 2016 | | March 15, 2017 | | Jan 15, 2023 |
| Equity offering redemption period (3) | | — | | — | | April 1, 2014 | | March 15, 2015 | | n/a |
| |
| (1) | On or after these dates, the Company has the option to redeem all or a portion of its senior notes at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption. |
| |
| (2) | At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes at the “make-whole” redemption prices specified in the Indentures plus any accrued and unpaid interest to the date of redemption. |
| |
| (3) | At any time prior to these dates, the Company may redeem up to 35% of the principal amount of its senior notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the Indentures plus any accrued and unpaid interest to the date of redemption. The optional redemption period for the 2019 Notes and 2020 Notes using equity offering proceeds expired on October 1, 2012 and October 1, 2013, respectively. |
The
Company may also redeem the Notes, in whole or in part, at the “make-whole” redemption prices specified in the Indentures plus accrued and unpaid interest at any time prior to October 1, 2014, October 1, 2015, and April 1, 2016 for the 2019 Notes, 2020 Notes, and 2021 Notes, respectively. In addition, the Company may redeem up to 35% of the 2019 Notes, 2020 Notes, and 2021 Notes prior to October 1, 2012, October 1, 2013, and April 1, 2014, respectively, under certain circumstances with the net cash proceeds from certain equity offerings. The NotesCompany’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. TheseHowever, as a result of the increase in credit ratings assigned to the Company's senior unsecured debt and release of credit facility collateral in December 2013 as described above, 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 S&P or Baa3 by Moody's 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 December 31,
2011. One2013. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C.
, and CLR Asset Holdings, LLC, which
currently hashave insignificant assets with no
independent assets orcurrent value and no operations, fully and unconditionally
guaranteesguarantee the
Notes.senior notes. The Company’s other subsidiary,
20 Broadway Associates LLC, the value of whose assets and operations are minor, does not guarantee the
Notes.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 consolidated balance sheets at December 31, 2013.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The items comprising the provision for income taxes are as follows for the periods presented:
| | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Current tax provision: | | | | | | | | | | | | |
Federal | | $ | 12,931 | | | $ | 12,545 | | | $ | 2,444 | |
State | | | 239 | | | | 308 | | | | 107 | |
| | | | | | | | | | | | |
Total current tax provision | | | 13,170 | | | | 12,853 | | | | 2,551 | |
Deferred tax provision: | | | | | | | | | | | | |
Federal | | | 212,406 | | | | 78,769 | | | | 35,302 | |
State | | | 32,797 | | | | (1,410 | ) | | | 817 | |
| | | | | | | | | | | | |
Total deferred tax provision | | | 245,203 | | | | 77,359 | | | | 36,119 | |
| | | | | | | | | | | | |
Total provision for income taxes | | $ | 258,373 | | | $ | 90,212 | | | $ | 38,670 | |
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Current income tax provision: | | | | | | |
| Federal | | $ | 6,193 |
| | $ | 9,191 |
| | $ | 12,931 |
|
| State | | 16 |
| | 1,326 |
| | 239 |
|
| Total current income tax provision | | 6,209 |
| | 10,517 |
| | 13,170 |
|
| Deferred income tax provision: | | | | | | |
| Federal | | 403,002 |
| | 383,157 |
| | 212,406 |
|
| State | | 39,619 |
| | 22,137 |
| | 32,797 |
|
| Total deferred income tax provision | | 442,621 |
| | 405,294 |
| | 245,203 |
|
| Total provision for income taxes | | $ | 448,830 |
| | $ | 415,811 |
| | $ | 258,373 |
|
The following table reconciles the provision for income taxes with income tax at the Federal statutory rate for the periods presented:
| | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Federal income tax provision at statutory rate (35%) | | $ | 240,606 | | | $ | 90,463 | | | $ | 38,503 | |
State income tax provision (benefit), net of Federal benefit | | | 17,684 | | | | (681 | ) | | | (108 | ) |
Other, net | | | 83 | | | | 430 | | | | 275 | |
| | | | | | | | | | | | |
Provision for income taxes | | $ | 258,373 | | | $ | 90,212 | | | $ | 38,670 | |
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Federal income tax provision at statutory rate (35%) | | $ | 424,567 |
| | $ | 404,319 |
| | $ | 240,606 |
|
| State income tax provision, net of Federal benefit | | 25,838 |
| | 15,213 |
| | 17,684 |
|
| Other, net | | (1,575 | ) | | (3,721 | ) | | 83 |
|
| Provision for income taxes | | $ | 448,830 |
| | $ | 415,811 |
| | $ | 258,373 |
|
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The components of the Company’s deferred tax assets and liabilities as of December 31,
20112013 and
20102012 are as follows:
| | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | |
| | | In thousands | |
Current: | | | | | | | | |
Deferred tax assets(1) | | | | | | | | |
Unrealized losses on derivatives | | $ | 42,030 | | | $ | 21,110 | |
Other expenses | | | 1,924 | | | | 603 | |
| | | | | | | | |
Total current deferred tax assets | | | 43,954 | | | | 21,713 | |
Noncurrent: | | | | | | | | |
Deferred tax assets | | | | | | | | |
Net operating loss carryforwards | | | 20,927 | | | | 20,772 | |
Unrealized losses on derivatives | | | 20,564 | | | | 43,030 | |
Alternative minimum tax carryforwards | | | 37,025 | | | | 24,095 | |
Other | | | 9,525 | | | | 4,394 | |
| | | | | | | | |
Total noncurrent deferred tax assets | | | 88,041 | | | | 92,291 | |
Deferred tax liabilities | | | | | | | | |
Property and equipment | | | 938,323 | | | | 675,132 | |
| | | | | | | | |
Total noncurrent deferred tax liabilities | | | 938,323 | | | | 675,132 | |
| | | | | | | | |
Net noncurrent deferred tax liabilities | | | 850,282 | | | | 582,841 | |
| | | | | | | | |
Net deferred tax liabilities | | $ | 806,328 | | | $ | 561,128 | |
|
| | | | | | | | |
| | | December 31, |
| In thousands | | 2013 | | 2012 |
| Current: | | | | |
| Deferred tax assets (1) | | | | |
| Non-cash losses on derivatives | | $ | 33,029 |
| | $ | — |
|
| Other | | 2,288 |
| | 2,413 |
|
| Total current deferred tax assets | | 35,317 |
| | 2,413 |
|
| Deferred tax liabilities | | | | |
| Other | | 645 |
| | 2,048 |
|
| Total current deferred tax liabilities | | 645 |
| | 2,048 |
|
| Net current deferred tax assets | | 34,672 |
| | 365 |
|
| Noncurrent: | | | | |
| Deferred tax assets | | | | |
| Net operating loss carryforwards | | 41,791 |
| | 40,441 |
|
| Non-cash losses on derivatives | | 2,975 |
| | — |
|
| Alternative minimum tax carryforwards | | 38,689 |
| | 27,380 |
|
| Other | | 20,220 |
| | 11,576 |
|
| Total noncurrent deferred tax assets | | 103,675 |
| | 79,397 |
|
| Deferred tax liabilities | | | | |
| Property and equipment | | 1,840,331 |
| | 1,330,551 |
|
| Other | | 156 |
| | 11,422 |
|
| Total noncurrent deferred tax liabilities | | 1,840,487 |
| | 1,341,973 |
|
| Net noncurrent deferred tax liabilities | | 1,736,812 |
| | 1,262,576 |
|
| Net deferred tax liabilities (2) | | $ | 1,702,140 |
| | $ | 1,262,211 |
|
| |
| (1) | Deferred and prepaid taxes on the accompanying consolidated balance sheets contain receivables of $3.7$9.7 million and $1.0 million for overpaidprepaid income taxes at December 31, 20112013, with no such prepayments at December 31, 2012. |
| |
| (2) | In addition to the 2012 provision for income taxes of $415.8 million, activity during 2012 includes an increase to deferred tax liabilities of $56.6 million related to the acquisition of assets from Wheatland Oil Inc. (see Note 14) and 2010, respectively.a decrease of $15.6 million related to the excess tax benefits of stock-based compensation. |
As of December 31, 2011,2013, the Company had Federal net operating loss carryforwards of $24.0 million which will expire beginning in 2027 and state net operating loss carryforwards totaling $380.0 million$1.0 billion which will expire beginning in 2017. The carryforwards have expiration periods that vary according to state jurisdiction. Included in the net operating loss carryforward is an excess tax benefit related to stock-based compensation of $22.5 million ($8.6 million tax effected) for which the deferred tax asset cannot be recorded until the utilization of the net operating loss carryforward reduces current taxes payable. When recorded, the offsetting account will be additional paid-in capital. In addition, theThe Company has an alternative minimum tax credit carryforwardcarryforwards of $37.0$39 million and a that have no expiration date. Any available statutory depletion carryforward, whichcarryforwards will be recognized when realized, of $10.9 million, neither of which expires.realized. The Company files income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. The earliest yearWith few exceptions, the Company is no longer subject to examination in each is 2006; however,U.S. Federal, state and local income tax examinations by tax authorities for years prior to May 15, 2007, the Company was an S corporation and any taxes for periods prior to that would be payable by the then existing shareholders.Continental Resources, Inc. and Subsidiaries2010.
Notes to Consolidated Financial Statements
Note 9. Lease Commitments
The Company’s operating lease obligations primarily represent leases for office equipment, communication towers and tanks for storage of hydraulic fracturing fluids. Lease expensespayments associated with the Company’s operating leases for the years ended December 31, 2013, 2012 and 2011 2010were $3.0 million, $2.2 million and 2009 were $1.7$1.7 million $1.7 million and $6.0 million, respectively., respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2011,2013 the minimum future rental commitments under operating leases having initial or remaining non-cancelable lease terms in excess of one year are as follows: | | | | |
In these years | | Total amount | |
| | | In thousands | |
2012 | | $ | 1,748 | |
2013 | | | 1,805 | |
2014 | | | 1,535 | |
2015 | | | 121 | |
2016 | | | 55 | |
| | | | |
Total obligations | | $ | 5,264 | |
|
| | | | |
| | Total amount |
| In these years | | In thousands |
| 2014 | | $ | 1,954 |
|
| 2015 | | 432 |
|
| 2016 | | 346 |
|
| 2017 | | 255 |
|
| 2018 | | 151 |
|
| Thereafter | | 182 |
|
| Total obligations | | $ | 3,320 |
|
Note 10. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of December 31, 2013. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets.
Drilling commitments – As of December 31, 2011,2013, the Company had drilling rig contracts with various terms extending through August 2014.January 2016. 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 December 31, 20112013 total approximately $137$110 million, of which $118$83 million is expected to be incurred in 2012, $132014, $26 million in 2013,2015, and $6less than $1 million in 2014. These drilling commitments are not recorded in the accompanying consolidated balance sheets.2016. Fracturing and well stimulation service agreementsagreement– The Company has an agreement with a third party whereby the third party will provide, on a take-or-pay basis, hydraulic fracturing services and related equipment to service certain of the Company’s properties in North Dakota and Montana. The agreement, has a term of three years, beginningwhich expires in October 2010, with two one-year extensions available toSeptember 2014, requires the Company at its discretion. Pursuant to the take-or-pay provisions, the Company is to pay a fixed rate per day for a minimum number of days per calendar quarter over the three-year term regardless of whether the services are provided. The agreement also stipulates the Company will bear the cost of certain products and materials used. Future commitments remaining as of December 31, 20112013 amount to approximately $39$16 million of, which $22 million is expected to be incurred in 2012 and $17 million in 2013. Since the inception of this agreement, thethrough September 2014.
Pipeline transportation commitments – The Company has been using the services more than the minimum number of days each quarter. Additionally, the Company has an agreement whereby a third party will provide coiled tubing well stimulation services for certain of the Company’s properties in Oklahoma at a fixed rate per month for calendar year 2012, resulting in total future commitments of approximately $5 million as of December 31, 2011. The commitments under these agreements are not recorded in the accompanying consolidated balance sheets.Firm transportation commitment –the Company has a five-yearentered into firm transportation commitment, beginning in August 2011,commitments to guarantee pipeline access capacity totaling 10,000 barrels ofon operational crude oil per day on a major pipelinepipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have 5-year terms extending as far as November 2017, require the Company to pay varying per-barrel transportation commitment is forcharges regardless of the amount of pipeline capacity used. Future commitments remaining as of December 31, 2013 under the operational crude oil pipeline transportation arrangements amount to approximately $43 million, of which $14 million is expected to be incurred in 2014, $14 million in 2015, $10 million in 2016, and $5 million in 2017.
The Company has also entered into a commitment to guarantee pipeline access capacity on an operational natural gas pipeline system to move a portion of its North region natural gas production to market. The commitment, which has a 10-year term ending in October 2023, requires the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments under the arrangement amount to approximately $24 million as of December 31, 2013, which is expected to be incurred ratably over its 10-year term.
Further, the Company is a party to additional 5-year firm transportation commitments for future 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 significant additional construction efforts by our counterparties before being completed. Future commitments under the non-operational arrangements total approximately $1.0 billion at December 31, 2013, 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 as discussed in Note 11. Related Party Transactions. These commitments represent aggregate
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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 Bakken fieldfourth quarter of 2014, which would obligate the Company for transportation charges totaling $36 million in the 2014 fourth quarter, $143 million per year in years 2015 through 2018, and $106 million in 2019 associated with those projects.
Rail transportation commitments – The Company has entered into firm transportation commitments to guarantee capacity on rail transportation facilities in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The rail commitments have various terms extending through June 2014 and require the Company to pay varying per-barrel transportation charges regardless of the amount of rail capacity used. Future commitments remaining as of December 31, 2013 under the rail transportation arrangements amount to approximately $10 million, which is expected to be incurred through June 2014.
The Company’s pipeline and rail transportation commitments are for production primarily in the North region where the Company allocates a significant portion of its capital expenditures. The commitment requires the Company to pay transportation reservation charges of $1.85 per barrel, or $6.8 million annually through August 2016, regardless of the amount of pipeline capacity used. The commitments under this agreement are not recorded in the accompanying consolidated balance sheets. The Company is not committed under this contract, or any other existing contract,these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.
Cost sharing commitment – Continental Resources, Inc.The Company has entered into an arrangement to share certain costs associated with a local utility company's construction and Subsidiaries
Notesinstallation of electrical infrastructure that will provide service to Consolidated Financial Statementsparts 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 December 31, 2013 total approximately
$25 million, of which $15 million is expected to be incurred in 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 has commencedis ongoing and information and documents are beingcontinue 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 givendue 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 such asincluding, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and similarother matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of December 31, 20112013 and 2010,2012, the Company has recorded a liability on the consolidated balance sheets under the caption “Other noncurrent liabilities” of $2.6$1.7 million and $4.6$2.4 million, respectively, for various matters, none of which are believed to be individually significant. Employee retirement plan – The Company maintains a defined contribution retirement plan for its employees and makes contributions to the plan, up to the contribution limits established by the Internal Revenue Service, based on a percentage of each eligible employee’s compensation. During 2009 and 2010, contributions to the plan were 5% of eligible employees’ compensation, excluding bonuses. During 2011, the Company’s contributions to the plan represented 3% of eligible employees’ compensation, including bonuses, in addition to matching 50% of eligible employees’ contributions up to 6% of eligible compensation. Expenses associated with the plan amounted to $3.0 million, $1.4 million, and $1.3 million for the years ended December 31, 2011, 2010, and 2009, respectively. Effective January 1, 2012, contributions to the plan represent 3% of eligible employees’ compensation, including bonuses, in addition to matching 100% of eligible employees’ contributions up to 4% of eligible compensation.Employee health claims – The Company generally self-insures employee health claims up to the first $125,000 per employee per year. Amounts paid above this level are reinsured through third-party providers. The Company generally self-insures employee workers’ compensation claims up to the first $300,000 per employee per claim. Amounts paid above this level are reinsured through third-party providers up to $1 million in excess of the self-insured retention. The Company accrues for claims that have been incurred but not yet reported based on a review of claims filed versus expected claims based on claims history. The accrued liability for health and workers’ compensation claims was $2.7 million and $1.9 million at December 31, 2011, and 2010, respectively.
Environmental Riskrisk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.
Note 11. Related Party Transactions
The Company sells a portion of its natural gas production to affiliates. For the years ended December 31, 2011, 2010,2013, 2012, and 2009,2011, these sales amounted to $53.5$105.1 million, $31.0$61.7 million, and $26.6$53.5 million, respectively, and are included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of income. At December 31, 20112013 and 2010, $12.32012, $12.7 million and $5.1 million, respectively, was due from these affiliates.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
and In August 2010,$11.7 million, respectively, was due to the Company began buying or sellingfrom these affiliates, which is included in the caption “Receivables—Affiliated parties” in the consolidated balance sheets.
The Company engages in crude oil trades with an affiliate. These purchases oraffiliate from time to time to obtain space on pipeline systems in the Company's operating areas. For the years ended December 31, 2012, and 2011, crude oil sales are done withto the affiliate each monthtotaled 21,000 barrels and 435,000 barrels, respectively, generating sales proceeds of $1.9 million and $41.7 million, respectively. There were no crude oil sales to the affiliate in 2013. In 2013 and 2012, the Company purchased 30,000 barrels and 2,000 barrels, respectively, from the affiliate for $3.0 million and $0.2 million, respectively, with the net amountno purchases being paid to, or receivedmade from the affiliate in the following month. In 2011, the Company sold 435,000 barrels to the affiliate for $41.7 million and purchased no barrels from the affiliate during the year. In 2010, the Company sold 104,000 barrels to the affiliate for $7.3 million and purchased 15,000 barrels from the affiliate for $1.2 million.2011. The Company incurred $1.4$2.2 million, $2.7 million, and $0.5$1.4 million in transportation and gathering expenses in 20112013, 2012, and 2010,2011, respectively, associated with these transactions. At both December 31, 2013 and 2012, $0.2 million was due from the Company to the affiliate associated with these transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets.
The Company contracts for field services such as compression and drilling rig services and purchases residue fuel gas and reclaimed crude oil from certain affiliates. The Company capitalized costs of $5.7 million, $5.0 million and $4.1 million in 2013, 2012, and 2011, respectively, associated with drilling rig services provided by an affiliate. Production and other expenses attributable to these affiliatesaffiliate transactions were $4.6$1.4 million $6.6, $2.0 million and $16.5$4.6 million for the years ended December 31, 2011, 20102013, 2012, and 2009,2011, respectively. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $30.8$48.5 million $30.8, $32.7 million and $90.4$30.8 million for the years ended December 31, 2013, 2012, and 2011, 2010 and 2009, respectively. The Company also received $146,000 in 2010 and $428,000 in 2009 from a former affiliate for saltwater disposal fees. Under a contract for natural gas sales to an affiliate, the Company incurred gathering and treatment fees which amounted to $4.6$4.7 million in 2011, $5.52013, $4.7 million in 20102012 and $4.5$4.6 million in 2009.2011. At December 31, 20112013 and 2010, $5.72012, $5.1 million and $3.3$5.6 million, respectively, was due to these affiliates related to these transactions.transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets.
Certain officers and other key employees of the Company own or control entities that own working and royalty interests in wells operated by the Company. The Company paid revenues to these affiliates, including royalties, of $46.8$2.3 million $17.7, $38.3 million, and $11.3$46.8 million and received payments from these affiliates of $67.5$1.3 million $20.9, $38.5 million, and $15.9$67.5 million during the years ended December 31, 2011, 20102013, 2012, and 2009,2011, respectively, relating to the operations of the respective properties. The Company also paid to these affiliates $4,900$277,000 in 2011, $48,0002012 and $4,900 in 2010, and $508,000 in 20092011 for their share of proceeds forfrom undeveloped leasehold sales.sales, with no such payments in 2013. At December 31, 20112013 and 2010, $18.82012, $0.4 million and $15.0$0.7 million was due from these affiliates and approximately $4.2$0.2 million and $1.1$0.3 million was due to these affiliates, respectively, relating to these transactions.In March 2011,
Prior to July 2012, the Company executed an agreement to acquire ownership of 20 Broadway Associates LLC (“20 Broadway”), an entity wholly owned by the Company’s principal shareholder. 20 Broadway’s sole asset was a building in Oklahoma City, Oklahoma where the Company is relocating its corporate headquarters in 2012. The Company paid $23.0 million for 20 Broadway, which was the amount paid by 20 Broadway to initially acquire the building in Oklahoma City in October 2010, including reimbursed commissions and closing costs.The Company leasesleased office space under an operating lease from an entity owned by the Company’s principal shareholder. The Company pays approximately $86,000 per month for the office space. Rents paid associated with this leasethe leases totaled $1.0approximately
$0.7 million $1.0 and $1.0 million and $0.9 million for the years ended December 31, 2012 and 2011, 2010respectively. The Company allows certain affiliates to use its corporate aircraft and 2009, respectively.crews and has used the aircraft and crews of those same affiliates from time to time in order to facilitate efficient transportation of Company personnel. The termrates charged between the parties vary by type of aircraft used. For usage during 2013, 2012, and 2011, the Company charged affiliates approximately $55,000, $112,000, and $235,000, respectively, for use of its corporate aircraft, crews and fuel and training costs and received $379,000 from the affiliate in 2013 for certain current and prior year charges. The Company was charged $51,000, $102,000, and $88,000, respectively, by affiliates for use of their aircraft and crews during 2013, 2012, and 2011 and paid $238,000 to the affiliates in 2013 for certain current and prior year charges.
In September 2012, the Company entered into 5-year firm transportation commitments under a joint tariff arrangement to guarantee pipeline access capacity totaling 10,000 barrels of crude oil per day on pipeline projects being developed by an affiliated party and an unaffiliated party that are not yet operational. The pipeline projects require additional construction efforts by those parties before being completed. The commitments require the Company to pay joint tariff transportation charges of $5.25 per barrel regardless of the lease continues through July 2012.amount of pipeline capacity used, which will be allocated between the affiliated party and unaffiliated party. Future commitments under the joint tariff arrangement, a portion of which will be allocated to the affiliate, total approximately
$96 million at December 31, 2013, representing aggregate joint tariff transportation charges expected to be incurred over the 5-year term assuming the pipeline projects are completed and become operational. The commitments under this arrangement are not recorded in the accompanying consolidated balance sheets. In August 2012, the Company acquired the assets of Wheatland Oil Inc. Wheatland is owned 75% by the Revocable Inter Vivos Trust of Harold G. Hamm, a trust of which Harold G. Hamm, the Company’s Chief Executive Officer, Chairman of the Board and principal shareholder is the trustee and sole beneficiary, and 25% by the Company’s Vice Chairman of Strategic Growth Initiatives, Jeffrey B. Hume. See Note 14. Property Transaction with Related Party for further discussion.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 12. Stock-Based Compensation
The Company has granted stock options and restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2000 Stock Option Plan (“2000 Plan”) and 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 underin the caption “General and administrative expenses” in the consolidated statements of income, is reflected in the table below for the periods presented. | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Non-cash equity compensation | | $ | 16,572 | | | $ | 11,691 | | | $ | 11,408 | |
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Non-cash equity compensation | | $ | 39,890 |
| | $ | 29,057 |
| | $ | 16,572 |
|
Effective October 1, 2000, the Company adopted the 2000 Plan and granted stock options to certain eligible employees.
These grants consisted of either incentive stock options, nonqualified stock options or a combination of both. The granted stock options vest ratably over either a three or five-year period commencing on the first anniversary of the grant date and expire ten years from the date of grant. On November 10, 2005, the 2000 Plan was terminated. As of
DecemberMarch 31,
2011,2012, all options
covering 2,227,163 sharesissued under the 2000 Plan had been exercised
and 540,868 had been canceled.or expired. The Company’sfollowing table summarizes stock option activity under the 2000 Plan from December 31, 2008 to December 31, 2011 is presented below:
| | | | | | | | | | | | | | | | |
| | | Outstanding | | | Exercisable | |
| | | Number of
options | | | Weighted
average
exercise
price | | | Number of
options | | | Weighted
average
exercise
price | |
Outstanding at December 31, 2008 | | | 450,200 | | | $ | 1.28 | | | | 450,200 | | | $ | 1.28 | |
Exercised | | | (138,010 | ) | | | 1.78 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at December 31, 2009 | | | 312,190 | | | | 1.06 | | | | 312,190 | | | | 1.06 | |
Exercised | | | (207,220 | ) | | | 1.24 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at December 31, 2010 | | | 104,970 | | | | 0.71 | | | | 104,970 | | | | 0.71 | |
Exercised | | | (18,470 | ) | | | 0.71 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at December 31, 2011 | | | 86,500 | | | | 0.71 | | | | 86,500 | | | | 0.71 | |
for the periods presented:
|
| | | | | | | | | | | | | | |
| | | Outstanding | | Exercisable |
| | | Number of options | | Weighted average exercise price | | Number of options | | Weighted average exercise price |
| Outstanding at December 31, 2010 | | 104,970 |
| | $ | 0.71 |
| | 104,970 |
| | $ | 0.71 |
|
| Exercised | | (18,470 | ) | | $ | 0.71 |
| | | | |
| Outstanding at December 31, 2011 | | 86,500 |
| | $ | 0.71 |
| | 86,500 |
| | $ | 0.71 |
|
| Exercised | | (86,500 | ) | | $ | 0.71 |
| | | | |
| Outstanding at December 31, 2012 | | — |
| | — |
| | — |
| | — |
|
The intrinsic value of a stock option is the amount by which the value of the underlying stock exceeds the exercise price of the option at its exercise date. The total intrinsic value of options exercised during the years ended December 31, 2012 and 2011 2010was $7.6 million and 2009 was $1.1$1.1 million $8.9 million and $5.3 million,, respectively. At December 31, 2011, all options were exercisable and had
Restricted stock
In May 2013, the Company's shareholders, upon recommendation by the Board of Directors, approved the adoption of the Company's 2013 Plan. The 2013 Plan is a
weighted average remaining life of 3 months with an aggregate intrinsic value of $5.7 million.Restricted Stock
On October 3, 2005,broad-based incentive plan that allows the Company adoptedto use, if desired, a variety of equity compensation alternatives in structuring compensation arrangements for the Company's officers, directors and select employees. Effective May 23, 2013, the 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan and reserved aprior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms.
The maximum number of 5,500,000 shares of common stock available for issuance under the 2013 Plan is 9,840,036 shares, which includes (i) 7,500,000 new shares authorized under the 2013 Plan, (ii) 1,840,036 shares that may be issued pursuantremained available for issuance under the 2005 Plan as of March 27, 2013 that have been transferred from the 2005 Plan to the 2013 Plan, and (iii) up to 500,000 shares available for issuance under the 2013 Plan to the extent such shares are forfeited or withheld for payment of income taxes related to existing awards outstanding under the 2005 Plan. As of December 31, 2011,2013, the Company had 2,631,287a maximum of 9,813,989 shares of restricted stock available to grant to officers, directors officers and keyselect employees under the 20052013 Plan.
Restricted stock is awarded in the name of the recipient and
except for the right of disposal, constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction
includingand, 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.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
A summary of changes in
the non-vested restricted shares from December 31,
20082010 to December 31,
20112013 is presented below:
| | | | | | | | |
| | | Number of
non-vested
shares | | | Weighted
average
grant-date
fair value | |
Non-vested restricted shares at December 31, 2008 | | | 1,110,892 | | | $ | 24.05 | |
Granted | | | 411,217 | | | | 28.94 | |
Vested | | | (369,784 | ) | | | 22.00 | |
Forfeited | | | (25,504 | ) | | | 21.98 | |
| | | | | | | | |
Non-vested restricted shares at December 31, 2009 | | | 1,126,821 | | | | 26.55 | |
Granted | | | 449,114 | | | | 48.71 | |
Vested | | | (412,143 | ) | | | 25.50 | |
Forfeited | | | (55,715 | ) | | | 30.52 | |
| | | | | | | | |
Non-vested restricted shares at December 31, 2010 | | | 1,108,077 | | | | 35.72 | |
Granted | | | 491,315 | | | | 63.59 | |
Vested | | | (359,601 | ) | | | 29.95 | |
Forfeited | | | (41,447 | ) | | | 41.93 | |
| | | | | | | | |
Non-vested restricted shares at December 31, 2011 | | | 1,198,344 | | | | 48.66 | |
|
| | | | | | | |
| | | Number of
non-vested
shares | | Weighted
average
grant-date
fair value |
| Non-vested restricted shares at December 31, 2010 | | 1,108,077 |
| | $ | 35.72 |
|
| Granted | | 491,315 |
| | 63.59 |
|
| Vested | | (359,601 | ) | | 29.95 |
|
| Forfeited | | (41,447 | ) | | 41.93 |
|
| Non-vested restricted shares at December 31, 2011 | | 1,198,344 |
| | $ | 48.66 |
|
| Granted | | 916,028 |
| | 73.46 |
|
| Vested | | (444,723 | ) | | 45.25 |
|
| Forfeited | | (40,187 | ) | | 59.05 |
|
| Non-vested restricted shares at December 31, 2012 | | 1,629,462 |
| | $ | 63.28 |
|
| Granted | | 261,259 |
| | 97.95 |
|
| Vested | | (464,809 | ) | | 47.30 |
|
| Forfeited | | (68,756 | ) | | 71.91 |
|
| Non-vested restricted shares at December 31, 2013 | | 1,357,156 |
| | $ | 74.99 |
|
The grant date fair value of restricted stock represents the average of the high and low intradayclosing market pricesprice 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 2011, 20102013, 2012 and 20092011 at the vesting date was $19.9$49.4 million $19.7, $33.0 million and $13.3$19.9 million, respectively. As of December 31, 2011,2013, there was $40.8approximately $55 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 1.71.5 years. Note 13.
Sale of Common StockOn March 9, 2011,Property Acquisitions and Dispositions
Acquisitions
In December 2012, the Company acquired certain producing and certain selling shareholders completedundeveloped properties in the Bakken play of North Dakota from a public offeringthird party for $663.3 million, of an aggregatewhich $477.1 million was allocated to producing properties. In the transaction, the Company acquired interests in approximately 119,000 net acres as well as producing properties with production of 10,000,000approximately 6,500 net barrels of oil equivalent per day.
In August 2012, the Company acquired the assets of Wheatland Oil Inc. through the issuance of shares of the Company’s common stock, including 9,170,000 shares issued and sold bystock. See Note 14. Property Transaction with Related Party for further discussion.
In February 2012, the Company acquired certain producing and 830,000 shares sold byundeveloped properties in the selling shareholders, atBakken play of North Dakota from a pricethird party for $276 million, of $68.00 per share ($65.45 per share, net ofwhich $51.7 million was allocated to producing properties. In the underwriting discount). The net proceeds totransaction, the Company fromacquired interests in approximately 23,100 net acres as well as producing properties with production of approximately 1,000 net barrels of oil equivalent per day.
Dispositions
In December 2012, the offering amountedCompany sold its producing crude oil and natural gas properties and supporting assets in its East region to $599.7a third party for $126.4 million after deducting the underwriting discount and offering-related expenses. The Company did not receive any proceeds from the sale of shares by the selling shareholders.. In connection with the offering,transaction, the Company grantedrecognized a pre-tax gain of $68.0 million, which included the underwriters a 30-day overallotment option to purchase up to an additional 1,500,000 shareseffect of common stock atremoving $8.3 million of asset retirement obligations for the public offering price, less the underwriting discount, to cover overallotments, if any.On March 25, 2011,disposed properties previously recognized by the Company completed the sale of an additional 910,000 shares of its common stock at a price of $68.00 per share ($65.45 per share, net of the underwriting discount) in connection with the underwriters’ partial exercise of the overallotment option grantedthat were assumed by the Company.buyer. The Company received additional net proceeds of $59.5 million, after deducting the underwriting discount, from the partial exercise of the overallotment option. The selling shareholders did not participate in the partial exercise of the overallotment option.
The Company used the total net proceeds from the offering of $659.2 million to repay all amounts then outstanding under its revolving credit facility and to fundtransaction excluded a portion of its 2011 capital budget.
the Company’s non-producing leasehold acreage in the East region, which was retained by the Company for future exploration and development opportunities. The transaction also allowed for the Company to retain an overriding royalty interest in certain of the disposed properties as well as rights to drill in potential unproven deeper formations that may exist below the disposed properties. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
In June 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Oklahoma to a third party for Note 14. Asset Dispositions$15.9 million
and recognized a pre-tax gain on the transaction of $15.9 million, which included the effect of removing $0.6 million of asset retirement obligations for the disposed properties previously recognized by the Company that were assumed by the buyer. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.
In February 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Wyoming to a third party for $84.4 million. In connection with the transaction, the Company recognized a pre-tax gain of $50.1 million, which included the effect of removing $11.1 million of asset retirement obligations for the disposed properties previously recognized by the Company that were assumed by the buyer. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.
During 2011, the Company assigned certain non-strategic properties located in Michigan, North Dakota, and Montana to third parties for total cash proceeds of $30.2 million.$30.2 million. In connection with the transactions, the Company recognized pre-tax gains totaling $21.4 million.$21.4 million. Substantially all of the properties disposed propertiesof in 2011 consisted of undeveloped leasehold acreage with no proved reserves and no production or revenues. In June 2010, the Company assigned certain non-strategic properties in Louisiana to a third party for cash proceeds of $35.4 million and recognized a pre-tax gain on the transaction of $31.7 million. The 2010 transaction involved undeveloped acreage with no proved reserves and no production or revenues.
The gains on
these transactionsthe above dispositions are included in
the caption “Gain on sale of assets, net” in the consolidated statements of income.
Note
15. Relocation of Corporate Headquarters14. Property Transaction with Related Party
In March 2011,2012, the Company announced plansentered into a Reorganization and Purchase and Sale Agreement (the “Agreement”) with Wheatland Oil Inc. ("Wheatland") and the shareholders of Wheatland. Wheatland is owned 75% by the Revocable Inter Vivos Trust of Harold G. Hamm, a trust of which Harold G. Hamm, the Company’s Chief Executive Officer, Chairman of the Board and principal shareholder is the trustee and sole beneficiary, and 25% by the Company’s Vice Chairman of Strategic Growth Initiatives, Jeffrey B. Hume. The Agreement provided for the acquisition by the Company, through the issuance of shares of the Company’s common stock, of all of Wheatland’s right, title and interest in and to relocatecertain crude oil and natural gas properties and related assets, in which the Company also owned an interest, in the states of Mississippi, Montana, North Dakota and Oklahoma and the assumption of certain liabilities related thereto.
The Wheatland transaction was consummated and closed on August 13, 2012, with an effective date of January 1, 2012. At closing, the Company issued an aggregate of approximately 3.9 million shares of its corporate headquarters from Enid, Oklahoma to Oklahoma City, Oklahoma. The relocation is expected to provide more convenient accesscommon stock, par value $0.01 per share, to the Company’s operations across the country, to its business partners and to an expanded poolshareholders of technical talent. The relocation is expected to be completed during 2012. The Company currently estimates it may incur a total of approximately $15 million to $25 million of costsWheatland in conjunction with its relocation,accordance with the majorityterms of such costs expected to be incurred in the secondAgreement. The fair value of the consideration transferred by the Company at closing was approximately $279 million. In 2013, Wheatland paid the Company approximately $0.5 million upon final settlement of purchase price adjustments under the terms of the Agreement.
For accounting purposes, the acquisition represented a transaction between entities under common control as Mr. Hamm is the controlling shareholder of both the Company and third quartersWheatland. Accordingly, the Company recorded the assets acquired and liabilities assumed at Wheatland’s carrying amount. The net book basis of 2012. The Company generally expects to recognizeWheatland’s assets was approximately $82 million, primarily representing $177 million for acquired crude oil and natural gas properties partially offset by $38 million of joint interest obligations assumed, $0.6 million of asset retirement obligations assumed and $57 million of deferred income tax liabilities recognized. For the majority of relocation costs in its consolidated financial statements when incurred. As ofyear ended December 31, 2011,2012, the Company has recognizedacquired Wheatland properties comprised approximately $3.2484 MBoe of the Company’s crude oil and natural gas production and approximately $38 million of costs associated with its relocation efforts, which are included in the caption “Generalcrude oil and administrative expenses” in the consolidated statementsnatural gas revenues.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note
16.15. Crude Oil and Natural Gas Property Information
The following table sets forth the Company’s results of operations from crude oil and natural gas producing activities for the years ended December 31,
2011, 20102013, 2012 and
2009. | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Crude oil and natural gas sales | | $ | 1,647,419 | | | $ | 948,524 | | | $ | 610,698 | |
Production expenses | | | (138,236 | ) | | | (93,203 | ) | | | (93,242 | ) |
Production taxes and other expenses | | | (144,810 | ) | | | (76,659 | ) | | | (45,645 | ) |
Exploration expenses | | | (27,920 | ) | | | (12,763 | ) | | | (12,615 | ) |
Depreciation, depletion, amortization and accretion | | | (384,301 | ) | | | (239,748 | ) | | | (204,489 | ) |
Property impairments | | | (108,458 | ) | | | (64,951 | ) | | | (83,694 | ) |
Income taxes | | | (321,447 | ) | | | (175,256 | ) | | | (64,985 | ) |
| | | | | | | | | | | | |
Results from crude oil and natural gas producing activities | | $ | 522,247 | | | $ | 285,944 | | | $ | 106,028 | |
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
2011.
|
| | | | | | | | | | | | |
| | Year ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Crude oil and natural gas sales | | $ | 3,606,774 |
| | $ | 2,379,433 |
| | $ | 1,647,419 |
|
| Production expenses | | (282,197 | ) | | (195,440 | ) | | (138,236 | ) |
| Production taxes and other expenses | | (332,130 | ) | | (228,438 | ) | | (144,810 | ) |
| Exploration expenses | | (34,947 | ) | | (23,507 | ) | | (27,920 | ) |
| Depreciation, depletion, amortization and accretion | | (953,796 | ) | | (683,207 | ) | | (384,301 | ) |
| Property impairments | | (220,508 | ) | | (122,274 | ) | | (108,458 | ) |
| Income taxes | | (659,783 | ) | | (428,095 | ) | | $ | (321,447 | ) |
| Results from crude oil and natural gas producing activities | | $ | 1,123,413 |
| | $ | 698,472 |
| | $ | 522,247 |
|
Costs incurred in crude oil and natural gas activities
Costs incurred, both capitalized and expensed, in connection with the Company’s crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2013, 2012 and 2011 2010 and 2009 are shownpresented below: | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Property Acquisition Costs: | | | | | | | | | | | | |
Proved | | $ | 65,315 | | | $ | 7,338 | | | $ | 1,217 | |
Unproved | | | 183,247 | | | | 340,064 | | | | 73,273 | |
| | | | | | | | | | | | |
Total property acquisition costs | | | 248,562 | | | | 347,402 | | | | 74,490 | |
Exploration Costs | | | 734,797 | | | | 289,175 | | | | 96,440 | |
Development Costs | | | 1,178,136 | | | | 565,551 | | | | 260,407 | |
| | | | | | | | | | | | |
Total | | $ | 2,161,495 | | | $ | 1,202,128 | | | $ | 431,337 | |
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Property Acquisition Costs: | | | | | | |
| Proved | | $ | 16,604 |
| | $ | 738,415 |
| | $ | 65,315 |
|
| Unproved | | 546,881 |
| | 745,601 |
| | 183,247 |
|
| Total property acquisition costs | | 563,485 |
| | 1,484,016 |
| | 248,562 |
|
| Exploration Costs | | 687,767 |
| | 857,681 |
| | 734,797 |
|
| Development Costs | | 2,549,203 |
| | 1,975,660 |
| | 1,178,136 |
|
| Total | | $ | 3,800,455 |
| | $ | 4,317,357 |
| | $ | 2,161,495 |
|
Exploration costs above include asset retirement costs of $1.7$1.8 million $0.6, $3.3 million and $0.4$1.7 million and development costs above include asset retirement costs of $3.7$6.0 million $4.7, $1.0 million and $0.9$3.7 million for the years ended December 31, 2013, 2012 and 2011, 2010 and 2009, respectively.
Aggregate capitalized costs
Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31,
20112013 and
20102012 are as follows:
| | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | |
| | | In thousands | |
Proved crude oil and natural gas properties | | $ | 5,376,109 | | | $ | 3,431,628 | |
Unproved crude oil and natural gas properties | | | 663,493 | | | | 547,077 | |
| | | | | | | | |
Total | | | 6,039,602 | | | | 3,978,705 | |
Less accumulated depreciation, depletion and amortization | | | (1,458,224 | ) | | | (1,059,315 | ) |
| | | | | | | | |
Net capitalized costs | | $ | 4,581,378 | | | $ | 2,919,390 | |
|
| | | | | | | | |
| | | December 31, |
| In thousands | | 2013 | | 2012 |
| Proved crude oil and natural gas properties | | $ | 12,423,878 |
| | $ | 8,980,505 |
|
| Unproved crude oil and natural gas properties | | 1,181,268 |
| | 1,073,944 |
|
| Total | | 13,605,146 |
| | 10,054,449 |
|
| Less accumulated depreciation, depletion and amortization | | (3,083,180 | ) | | (2,090,845 | ) |
| Net capitalized costs | | $ | 10,521,966 |
| | $ | 7,963,604 |
|
Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling operations are complete, management determinesattempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved.proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of income as dry hole costs, a component of “Exploration expenses”. Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities.
On a quarterly basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period.
period of determination.
The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended:
| | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Balance at January 1 | | $ | 92,806 | | | $ | 22,856 | | | $ | 46,274 | |
Additions to capitalized exploratory well costs pending determination of proved reserves | | | 500,046 | | | | 185,713 | | | | 50,765 | |
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | | | (456,780 | ) | | | (112,739 | ) | | | (67,706 | ) |
Capitalized exploratory well costs charged to expense | | | (7,949 | ) | | | (3,024 | ) | | | (6,477 | ) |
| | | | | | | | | | | | |
Balance at December 31 | | $ | 128,123 | | | $ | 92,806 | | | $ | 22,856 | |
Number of wells | | | 56 | | | | 87 | | | | 20 | |
|
| | | | | | | | | | | | |
| | | Year ended December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Balance at January 1 | | $ | 92,699 |
| | $ | 128,123 |
| | $ | 92,806 |
|
| Additions to capitalized exploratory well costs pending determination of proved reserves | | 548,933 |
| | 485,530 |
| | 500,046 |
|
| Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | | (479,507 | ) | | (520,187 | ) | | (456,780 | ) |
| Capitalized exploratory well costs charged to expense | | (9,350 | ) | | (767 | ) | | (7,949 | ) |
| Balance at December 31 | | $ | 152,775 |
| | $ | 92,699 |
| | $ | 128,123 |
|
| Number of gross wells | | 67 |
| | 46 |
| | 56 |
|
Note
17.16. Supplemental Crude Oil and Natural Gas Information (Unaudited)
The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. ("Ryder Scott") prepared reserve estimates for properties comprising approximately 96%99%, 94%99%, and 90%96% of the Company’s discounted future net cash flows (PV-10) as of December 31, 2011, 2010,2013, 2012, and 2009,2011, respectively. Properties comprising 97%99% of proved crude oil reserves and 81%94% of proved natural gas reserves were evaluated by Ryder Scott as of December 31, 2011.2013. Remaining reserve estimates were prepared by the Company’s internal technical staff. All reserves stated herein are located in the United States. We adopted the provisions of the amendments onModernization of Oil and Gas Reporting for the year ended December 31, 2009. Such amendments increased the disclosures required regarding the Company’s reserves, changed the definition of proved reserves and changed the pricing assumptions. Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic
conditions, operating methods, and
operating conditions.government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured, and estimates of engineers other than the Company’s might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
Results of drilling, testing and production subsequentPeriodic revisions to the
dateestimated reserves and future cash flows may be necessary as a result of
the estimate may justify revisiona number of
such estimate.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. Accordingly, reserve estimates
are often differentmay differ significantly from the quantities of crude oil and natural gas ultimately recovered.
Reserves at December 31,
2011, 20102013, 2012 and
20092011 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules.
Reserves at December 31, 2008 were computed using year-end commodity prices pursuant to previous SEC rules.Natural gas imbalance receivables and payables for each of the three years ended December 31,
2011, 20102013, 2012 and
20092011 were not material and have not been included in the reserve estimates.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Proved crude oil and natural gas reserves
Changes in proved reserves were as follows for the periods presented:
|
| | | | | | | | | |
| | | Crude Oil
(MBbls) | | Natural Gas
(MMcf) | | Total
(MBoe) |
| Proved reserves as of December 31, 2010 | | 224,784 |
| | 839,568 |
| | 364,712 |
|
| Revisions of previous estimates | | 28,607 |
| | (158,219 | ) | | 2,237 |
|
| Extensions, discoveries and other additions | | 87,465 |
| | 447,098 |
| | 161,981 |
|
| Production | | (16,469 | ) | | (36,671 | ) | | (22,581 | ) |
| Sales of minerals in place | | — |
| | — |
| | — |
|
| Purchases of minerals in place | | 1,746 |
| | 2,056 |
| | 2,089 |
|
| Proved reserves as of December 31, 2011 | | 326,133 |
| | 1,093,832 |
| | 508,438 |
|
| Revisions of previous estimates | | 33,272 |
| | (174,736 | ) | | 4,149 |
|
| Extensions, discoveries and other additions | | 166,844 |
| | 400,848 |
| | 233,652 |
|
| Production | | (25,070 | ) | | (63,875 | ) | | (35,716 | ) |
| Sales of minerals in place | | (7,165 | ) | | (4,046 | ) | | (7,838 | ) |
| Purchases of minerals in place | | 67,149 |
| | 89,061 |
| | 81,992 |
|
| Proved reserves as of December 31, 2012 | | 561,163 |
| | 1,341,084 |
| | 784,677 |
|
| Revisions of previous estimates | | (55,783 | ) | | (241,623 | ) | | (96,054 | ) |
| Extensions, discoveries and other additions | | 267,009 |
| | 1,065,870 |
| | 444,654 |
|
| Production | | (34,989 | ) | | (87,730 | ) | | (49,610 | ) |
| Sales of minerals in place | | — |
| | — |
| | — |
|
| Purchases of minerals in place | | 388 |
| | 419 |
| | 458 |
|
| Proved reserves as of December 31, 2013 | | 737,788 |
| | 2,078,020 |
| | 1,084,125 |
|
Revisions of previous estimates. | | | | | | | | |
| | | Crude Oil
(MBbls) | | | Natural Gas
(MMcf) | |
Proved reserves as of December 31, 2008 | | | 106,239 | | | | 318,138 | |
Revisions of previous estimates | | | 1,609 | | | | (2,485 | ) |
Extensions, discoveries and other additions | | | 75,450 | | | | 210,029 | |
Production | | | (10,022 | ) | | | (21,606 | ) |
Sales of minerals in place | | | — | | | | — | |
Purchases of minerals in place | | | 4 | | | | 4 | |
| | | | | | | | |
Proved reserves as of December 31, 2009 | | | 173,280 | | | | 504,080 | |
Revisions of previous estimates | | | 14,414 | | | | 79,285 | |
Extensions, discoveries and other additions | | | 48,542 | | | | 280,146 | |
Production | | | (11,820 | ) | | | (23,943 | ) |
Sales of minerals in place | | | — | | | | — | |
Purchases of minerals in place | | | 368 | | | | — | |
| | | | | | | | |
Proved reserves as of December 31, 2010 | | | 224,784 | | | | 839,568 | |
Revisions of previous estimates | | | 28,607 | | | | (158,219 | ) |
Extensions, discoveries and other additions | | | 87,465 | | | | 447,098 | |
Production | | | (16,469 | ) | | | (36,671 | ) |
Sales of minerals in place | | | — | | | | — | |
Purchases of minerals in place | | | 1,746 | | | | 2,056 | |
| | | | | | | | |
Proved reserves as of December 31, 2011 | | | 326,133 | | | | 1,093,832 | |
Revisions. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. Revisions
Upward revisions to crude oil reserves for both of the yearyears ended December 31, 20102011 and 2012 were due to better than anticipated production performance, and higher average commodity prices throughout 2010 as compared to 2009. Revisions to crude oil reserves for the year ended December 31,with 2011 were due to better than anticipated production performance andrevisions also being positively impacted by higher average commodity prices throughout 2011 as compared to 2010. RevisionsDownward revisions to natural gas reserves for both of the years ended December 31, 2011 and 2012 were due to the removal of proved undeveloped ("PUD") reserves for certain dry gas properties not expected to be developed given the pricing environment for natural gas.
Revisions for the year ended December 31,
2011 were2013 primarily
duerepresent the removal of PUD reserves resulting from a decision in 2013 to allocate a greater focus of the Company's 5-year growth plan to drilling programs in higher rates-of-return crude oil and liquids-rich natural gas areas of the Bakken and SCOOP while continuing to build on the early success in the Company's development of the Lower Three Forks reservoirs in the Bakken. Another contributing factor is the Company's increased focus on multi-well pad drilling in the Bakken, which resulted in the removal of PUDs in certain areas in favor of PUDs more likely to be developed with pad drilling where operating efficiencies may be realized to maximize rates of return. These factors contributed to the removal of
135.442 MMBo and 235 Bcf
(81 MMBoe) of
proved undevelopedPUD reserves
primarily resulting from management’s decision to defer drilling on certain dry gas properties in
the Arkoma Woodford play in Oklahoma given the current and projected prices for natural gas.2013.
Extensions, discoveries and other additions.These are additions to proved reserves that resultresulting from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields.
Extensions, discoveries and other additions for
the year ended December 31, 2009 include increases in proved undeveloped locations as a resulteach of the
changethree years reflected in the
SEC’s rules in 2009 to allow producers to report additional undrilled locations beyond one offset on each side of a producing well where there is reasonable certainty of economic producibility. Extensions, discoveries and other additions for the year ended December 31, 2010table above were primarily due to increases in proved reserves associated with our successful drilling activity
and strong production growth in the Bakken
fieldfield. Proved reserve additions in
North Dakota. Extensions, discoveriesthe Bakken totaled 227 MMBo and
other additions293 Bcf (276 MMBoe) for the year ended December 31,
20112013. Additionally, 2013 extensions and discoveries were
primarily due to increases in proved reserves associated with oursignificantly impacted by successful drilling
activityresults in the
emerging SCOOP play, resulting in 36 MMBo and 730 Bcf (158 MMBoe) of proved reserve additions during the year. Significant progress continued to be made in 2013 in developing and expanding the Company's Bakken
field in North Dakota and
Anadarko Woodford play in Oklahoma.The increase in 2009 reserves described above had an effect on our depreciation, depletionSCOOP assets, both laterally and amortization, net incomevertically, through strategic exploration, development, planning and earnings per share for the fourth quartertechnology.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
change
Sales of minerals in pricing methodology had onplace. These are reductions to proved reserves resulting from the reserves as discussed above,disposition of properties during a period. During the year ended December 31, 2012, the Company is unable to estimatedisposed of certain non-strategic properties in Oklahoma, Wyoming, and the effectEast region. See Note 13. Property Acquisitions and Dispositions for further discussion of the remaining changes on 2009 becauseCompany’s 2012 dispositions.
Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a comparative reserve report prepared underperiod. Purchases for the previous SEC rules does not exist.year ended December 31, 2012 primarily reflected the Company’s acquisitions of properties in the Bakken play of North Dakota during the year. See
Note 13. Property Acquisitions and Dispositions and Note 14. Property Transaction with Related Party for further discussion of the Company’s 2012 acquisitions. The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31,
2011, 20102013, 2012 and
2009: | | | | | | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
Proved Developed Reserves | | | | | | | | | | | | |
Crude oil (MBbl) | | | 145,024 | | | | 101,272 | | | | 85,270 | |
Natural Gas (MMcf) | | | 361,265 | | | | 234,699 | | | | 169,782 | |
| | | | | | | | | | | | |
Total (MBoe) | | | 205,235 | | | | 140,389 | | | | 113,567 | |
Proved Undeveloped Reserves | | | | | | | | | | | | |
Crude oil (MBbl) | | | 181,109 | | | | 123,512 | | | | 88,010 | |
Natural Gas (MMcf) | | | 732,567 | | | | 604,869 | | | | 334,298 | |
| | | | | | | | | | | | |
Total (MBoe) | | | 303,203 | | | | 224,323 | | | | 143,726 | |
Total Proved Reserves | | | | | | | | | | | | |
Crude oil (MBbl) | | | 326,133 | | | | 224,784 | | | | 173,280 | |
Natural Gas (MMcf) | | | 1,093,832 | | | | 839,568 | | | | 504,080 | |
| | | | | | | | | | | | |
Total (MBoe) | | | 508,438 | | | | 364,712 | | | | 257,293 | |
2011:
|
| | | | | | | | | |
| | | December 31, |
| | | 2013 | | 2012 | | 2011 |
| Proved Developed Reserves | | | | | | |
| Crude oil (MBbl) | | 278,630 |
| | 226,870 |
| | 145,024 |
|
| Natural Gas (MMcf) | | 768,969 |
| | 545,499 |
| | 361,265 |
|
| Total (MBoe) | | 406,792 |
| | 317,786 |
| | 205,235 |
|
| Proved Undeveloped Reserves | | | | | | |
| Crude oil (MBbl) | | 459,158 |
| | 334,293 |
| | 181,109 |
|
| Natural Gas (MMcf) | | 1,309,051 |
| | 795,585 |
| | 732,567 |
|
| Total (MBoe) | | 677,333 |
| | 466,891 |
| | 303,203 |
|
| Total Proved Reserves | | | | | | |
| Crude oil (MBbl) | | 737,788 |
| | 561,163 |
| | 326,133 |
|
| Natural Gas (MMcf) | | 2,078,020 |
| | 1,341,084 |
| | 1,093,832 |
|
| Total (MBoe) | | 1,084,125 |
| | 784,677 |
| | 508,438 |
|
Proved developed reserves are
proved reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are
proved reserves that require incremental capital expenditures to recover. Natural gas is converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil.
Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves
The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31,
2011, 20102013, 2012 and
2009. | | | | | | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Future cash inflows | | $ | 35,042,916 | | | $ | 20,420,667 | | | $ | 10,993,595 | |
Future production costs | | | (7,495,552 | ) | | | (4,931,251 | ) | | | (3,190,748 | ) |
Future development and abandonment costs | | | (5,073,043 | ) | | | (3,517,389 | ) | | | (2,045,242 | ) |
Future income taxes | | | (5,956,615 | ) | | | (2,890,644 | ) | | | (1,268,119 | ) |
| | | | | | | | | | | | |
Future net cash flows | | | 16,517,706 | | | | 9,081,383 | | | | 4,489,486 | |
10% annual discount for estimated timing of cash flows | | | (9,012,350 | ) | | | (5,296,061 | ) | | | (2,647,946 | ) |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows | | $ | 7,505,356 | | | $ | 3,785,322 | | | $ | 1,841,540 | |
2011.
|
| | | | | | | | | | | | |
| | | December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Future cash inflows | | $ | 78,646,274 |
| | $ | 54,362,574 |
| | $ | 35,042,916 |
|
| Future production costs | | (21,333,460 | ) | | (13,103,469 | ) | | (7,495,552 | ) |
| Future development and abandonment costs | | (10,250,789 | ) | | (8,295,130 | ) | | (5,073,043 | ) |
| Future income taxes | | (12,447,127 | ) | | (8,500,766 | ) | | (5,956,615 | ) |
| Future net cash flows | | 34,614,898 |
| | 24,463,209 |
| | 16,517,706 |
|
| 10% annual discount for estimated timing of cash flows | | (18,319,131 | ) | | (13,282,852 | ) | | (9,012,350 | ) |
| Standardized measure of discounted future net cash flows | | $ | 16,295,767 |
| | $ | 11,180,357 |
| | $ | 7,505,356 |
|
The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $88.71, $71.92,$91.50, $86.56, and $52.76$88.71 per barrel at December 31, 2011, 20102013, 2012 and 2009,2011, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $5.59, $5.07,$5.36, $4.31, and $3.67$5.59 per Mcf at December 31, 2011, 20102013, 2012 and 2009,2011, respectively. Future cash flows are reduced by estimated future costs to develop and produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions. The expected tax benefits to be realized from the utilization of net operating loss carryforwards and known tax credits are used in the computation of future income tax cash flows. The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years:
| | | | | | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | In thousands | |
Standardized measure of discounted future net cash flows at beginning of year | | $ | 3,785,322 | | | $ | 1,841,540 | | | $ | 1,277,101 | |
| | | | | | | | | | | | |
Extensions, discoveries and improved recoveries, less related costs | | | 2,276,355 | | | | 926,938 | | | | 458,352 | |
Revisions of previous quantity estimates | | | 133,990 | | | | 490,563 | | | | 38,360 | |
Changes in estimated future development and abandonment costs | | | (70,219 | ) | | | (376,848 | ) | | | 23,136 | |
Purchases (sales) of minerals in place | | | 56,246 | | | | 8,022 | | | | 78 | |
Net change in prices and production costs | | | 1,855,532 | | | | 1,177,446 | | | | 417,739 | |
Accretion of discount | | | 378,532 | | | | 184,154 | | | | 127,710 | |
Sales of crude oil and natural gas produced, net of production costs | | | (1,364,373 | ) | | | (778,662 | ) | | | (471,811 | ) |
Development costs incurred during the period | | | 528,737 | | | | 356,992 | | | | 125,048 | |
Change in timing of estimated future production and other | | | 773,279 | | | | 397,669 | | | | 4,082 | |
Change in income taxes | | | (848,045 | ) | | | (442,492 | ) | | | (158,255 | ) |
| | | | | | | | | | | | |
Net change | | | 3,720,034 | | | | 1,943,782 | | | | 564,439 | |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows at end of year | | $ | 7,505,356 | | | $ | 3,785,322 | | | $ | 1,841,540 | |
|
| | | | | | | | | | | | |
| | | December 31, |
| In thousands | | 2013 | | 2012 | | 2011 |
| Standardized measure of discounted future net cash flows at January 1 | | $ | 11,180,357 |
| | $ | 7,505,356 |
| | $ | 3,785,322 |
|
| Extensions, discoveries and improved recoveries, less related costs | | 6,613,665 |
| | 3,724,136 |
| | 2,276,355 |
|
| Revisions of previous quantity estimates | | (1,765,300 | ) | | 254,493 |
| | 133,990 |
|
| Changes in estimated future development and abandonment costs | | 1,942,585 |
| | (298,148 | ) | | (70,219 | ) |
| Purchases (sales) of minerals in place, net | | 12,012 |
| | 1,171,047 |
| | 56,246 |
|
| Net change in prices and production costs | | 263,541 |
| | (530,515 | ) | | 1,855,532 |
|
| Accretion of discount | | 1,118,036 |
| | 750,536 |
| | 378,532 |
|
| Sales of crude oil and natural gas produced, net of production costs | | (2,992,447 | ) | | (1,955,555 | ) | | (1,364,373 | ) |
| Development costs incurred during the period | | 1,210,223 |
| | 1,095,156 |
| | 528,737 |
|
| Change in timing of estimated future production and other | | 464,111 |
| | (102,519 | ) | | 773,279 |
|
| Change in income taxes | | (1,751,016 | ) | | (433,630 | ) | | (848,045 | ) |
| Net change | | 5,115,410 |
| | 3,675,001 |
| | 3,720,034 |
|
| Standardized measure of discounted future net cash flows at December 31 | | $ | 16,295,767 |
| | $ | 11,180,357 |
| | $ | 7,505,356 |
|
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note
18.17. Quarterly Financial Data (Unaudited)
The Company’s unaudited quarterly financial data for 20112013 and 20102012 is summarized below. | | | | | | | | | | | | | | | | |
| | | Quarter ended | |
| | | March 31 | | | June 30 | | | September 30 | | | December 31 | |
| | | In thousands, except per share data | |
2011 | | | | | | | | | | | | | | | | |
Total revenues (1) | | $ | (36,210 | ) | | $ | 602,892 | | | $ | 968,989 | | | $ | 114,118 | |
Gain (loss) on derivative instruments, net (1) | | $ | (369,303 | ) | | $ | 204,453 | | | $ | 537,340 | | | $ | (402,539 | ) |
Income (loss) from operations | | $ | (202,893 | ) | | $ | 404,308 | | | $ | 727,618 | | | $ | (168,281 | ) |
Net income (loss) | | $ | (137,201 | ) | | $ | 239,194 | | | $ | 439,143 | | | $ | (112,064 | ) |
Net income (loss) per share: | | | | | | | | | | | | | | | | |
Basic | | $ | (0.80 | ) | | $ | 1.33 | | | $ | 2.45 | | | $ | (0.62 | ) |
Diluted | | $ | (0.80 | ) | | $ | 1.33 | | | $ | 2.44 | | | $ | (0.62 | ) |
2010 | | | | | | | | | | | | | | | | |
Total revenues (1) | | $ | 248,268 | | | $ | 279,968 | | | $ | 219,450 | | | $ | 91,379 | |
Gain (loss) on derivative instruments, net (1) | | $ | 26,344 | | | $ | 55,465 | | | $ | (24,183 | ) | | $ | (188,388 | ) |
Income (loss) from operations | | $ | 124,529 | | | $ | 176,323 | | | $ | 76,356 | | | $ | (66,887 | ) |
Net income (loss) | | $ | 72,465 | | | $ | 101,741 | | | $ | 39,077 | | | $ | (45,028 | ) |
Net income (loss) per share: | | | | | | | | | | | | | | | | |
Basic | | $ | 0.43 | | | $ | 0.60 | | | $ | 0.23 | | | $ | (0.27 | ) |
Diluted | | $ | 0.43 | | | $ | 0.60 | | | $ | 0.23 | | | $ | (0.27 | ) |
|
| | | | | | | | | | | | | | | | |
| | | Quarter ended |
| In thousands, except per share data | | March 31 | | June 30 | | September 30 | | December 31 |
| 2013 | | | | | | | | |
| Total revenues (1) | | $ | 710,229 |
| | $ | 1,100,752 |
| | $ | 823,835 |
| | $ | 820,334 |
|
| Gain (loss) on derivative instruments, net (1) | | $ | (84,831 | ) | | $ | 199,056 |
| | $ | (203,774 | ) | | $ | (102,202 | ) |
| Income from operations | | $ | 270,146 |
| | $ | 573,872 |
| | $ | 328,043 |
| | $ | 273,706 |
|
| Net income | | $ | 140,627 |
| | $ | 323,270 |
| | $ | 167,498 |
| | $ | 132,824 |
|
| Net income per share: | | | | | | | | |
| Basic | | $ | 0.76 |
| | $ | 1.76 |
| | $ | 0.91 |
| | $ | 0.72 |
|
| Diluted | | $ | 0.76 |
| | $ | 1.75 |
| | $ | 0.91 |
| | $ | 0.72 |
|
| 2012 | | | | | | | | |
| Total revenues (1) | | $ | 395,100 |
| | $ | 1,004,719 |
| | $ | 483,729 |
| | $ | 688,972 |
|
| Gain (loss) on derivative instruments, net (1) | | $ | (169,057 | ) | | $ | 471,728 |
| | $ | (158,294 | ) | | $ | 9,639 |
|
| Income from operations | | $ | 135,591 |
| | $ | 686,474 |
| | $ | 105,522 |
| | $ | 365,220 |
|
| Net income | | $ | 69,094 |
| | $ | 405,684 |
| | $ | 44,096 |
| | $ | 220,511 |
|
| Net income per share: | | | | | | | | |
| Basic | | $ | 0.38 |
| | $ | 2.26 |
| | $ | 0.24 |
| | $ | 1.20 |
|
| Diluted | | $ | 0.38 |
| | $ | 2.25 |
| | $ | 0.24 |
| | $ | 1.19 |
|
| |
| (1) | Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of income and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations at quarter-end have resultedeach quarter can result in significant swings in mark-to-market gains and losses, which has affectedaffects comparability between periods. Derivative losses exceeded crude oil and natural gas sales for the quarter ended March 31, 2011, resulting in negative total revenues for that period. |
| |
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
There have been no changes in accountants or any disagreements with accountants.
| |
| Item 9A. | 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 December 31,
20112013 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
ourits Chief Executive Officer and
our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors during the fourth quarter of 2013 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our Company’s management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.
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 risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on our evaluation under the framework inInternal Control—Integrated Framework (1992), the management of our Company concluded that our internal control over financial reporting was effective as of December 31, 2011.2013. The effectiveness of our internal control over financial reporting as of December 31,
20112013 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report that follows.
Chairman of the Board and Chief Executive Officer
Senior Vice President, Chief Financial Officer and Treasurer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Continental Resources, Inc.
We have audited the internal control over financial reporting of Continental Resources, Inc. (an Oklahoma corporation) and Subsidiaries’Subsidiaries (the Company) internal control over financial reporting“Company”) as of December 31, 2011,2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanyingManagement’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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 risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Continental Resources, Inc. and Subsidiariesthe Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011,2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated
balance sheetsfinancial statements of
Continental Resources, Inc. and Subsidiariesthe Company as of
December 31, 2011 and
2010, andfor the
related consolidated statements of income, shareholders’ equity and cash flows for each of the three years in the periodyear ended December 31,
20112013, and our report dated February
24, 201226, 2014 expressed an unqualified
opinion.opinion on those financial statements. |
|
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| /s/ GRANT THORNTON LLP |
|
| Oklahoma City, Oklahoma |
February 24, 201226, 2014 |
Changes in Internal Control over Financial Reporting
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors during the fourth quarter of 2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
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| Item 9B. | Other Information |
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| Item 10. | Directors, Executive Officers and Corporate Governance |
Information as to Item 10 will be set forth in the Proxy Statement for the Annual Meeting of Shareholders to be held in
2012May 2014 (the “Annual Meeting”) and is incorporated herein by reference.
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| Item 11. | Executive Compensation |
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
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| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
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| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
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| Item 14. | Principal Accounting Fees and Services |
Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
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| Item 15. | Exhibits, Financial Statement Schedules |
The
Consolidated Financial Statementsconsolidated financial statements of Continental Resources, Inc.
and Subsidiaries and the Report of Independent Registered Public Accounting Firm are included in
Part II, Item 8 of this report beginning on page
73.67.
(2) Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes thereto.
The exhibits required to be filed or furnished pursuant to Item 601 of Regulation S-K are set forth below.
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3.1***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*** | |
| 3.2 | | SecondThird 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. |
4.1*** | |
| 4.1 | | Registration Rights Agreement dated as of May 18, 2007 by and among Continental Resources, Inc., the Revocable Inter Vivos Trust of Harold G. Hamm, the Harold Hamm DST Trust and the Harold Hamm HJ Trust. |
| Trust filed February 24, 2012 as Exhibit 4.1 to the Company’s 2011 Form 10-K (Commission File No. 001-32886) and incorporated herein by reference. |
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| 4.2 | | Specimen Common Stock Certificate filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1 (Commission File No. 333-132257) filed April 14, 2006 and incorporated herein by reference. |
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| 4.3 | | Indenture dated as of September 23, 2009 among Continental Resources, Inc., Banner Pipeline Company, L.L.C. and Wilmington Trust FSB, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed September 24, 2009 and incorporated herein by reference. |
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| 4.4 | | Indenture dated as of April 5, 2010 among Continental Resources, Inc., Banner Pipeline Company, L.L.C. and Wilmington Trust FSB, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed April 7, 2010 and incorporated herein by reference. |
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| 4.5 | | Indenture dated as of September 16, 2010 among Continental Resources, Inc., Banner Pipeline Company, L.L.C. and Wilmington Trust FSB, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed September 17, 2010 and incorporated herein by reference. |
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10.1†4.6 | | Indenture dated as of March 8, 2012 among Continental Resources, Inc. 2000 Stock Option Plan, Banner Pipeline Company, L.L.C. and Wilmington Trust, National Association, as trustee, filed as Exhibit 10.64.1 to the Company’s Registration StatementCurrent Report on Form S-18-K (Commission File No. 333-132257)001-32886) filed April 14, 2006March 8, 2012 and incorporated herein by reference. |
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10.2† | | First Amendment to |
| 4.7 | | Indenture dated as of April 5, 2013 among Continental Resources, Inc. 2000 Stock Option Plan, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC and Wilmington Trust, National Association, as trustee, filed as Exhibit 10.74.1 to the Company’s Registration StatementCurrent Report on Form S-18-K (Commission File No. 333-132257)001-32886) filed April 14, 200611, 2013 and incorporated herein by reference. |
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10.3† | | Form |
| 4.8 | | Registration Rights Agreement dated as of Incentive Stock Option AgreementAugust 13, 2012 among Continental Resources, Inc., the Revocable Inter Vivos Trust of Harold G. Hamm, and Jeffrey B. Hume filed as Exhibit 10.84.1 to the Company’s Registration StatementCurrent Report on Form S-18-K (Commission File No. 333-132257)001-32886) filed April 14, 2006August 17, 2012 and incorporated herein by reference. |
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10.4†10.1† | | Amended and Restated Continental Resources, Inc. 2005 Long-Term Incentive Plan effective as of April 3, 2006 filed as Exhibit 10.9 to the Company’s Registration Statement on Form S-1 (Commission File No. 333-132257) filed April 14, 2006 and incorporated herein by reference. |
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10.5†10.2† | | Form of Restricted Stock Award Agreement filed as Exhibit 10.10 to the Company’s Registration Statement on Form S-1 (Commission File No. 333-132257) filed April 14, 2006 and incorporated herein by reference. |
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10.6†10.3† | | Form of Indemnification Agreement between Continental Resources, Inc. and each of the directors and executive officers thereof filed as Exhibit 10.12 to the Company’s Registration Statement on Form S-1 (Commission File No. 333-132257) filed April 14, 2006 and incorporated herein by reference. |
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10.7†10.4† | | Membership Interest Assignment Agreement by and between Continental Resources, Inc., the Harold Hamm Revocable Inter Vivos Trust, the Harold Hamm HJ Trust and the Harold Hamm DST Trust dated March 30, 2006 filed as Exhibit 10.13 to the Company’s Registration Statement on Form S-1 (Commission File No. 333-132257) filed April 14, 2006 and incorporated herein by reference. |
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10.8***10.5 | | Crude oil transportation agreement between Banner Pipeline Company, L.L.C., a wholly owned subsidiary of Continental Resources, Inc. and Banner Transportation Company dated July 11, 2007 originally filed February 24, 2012 as Exhibit 99.110.8 to the Company’s Current Report on2011 Form 8-K10-K (Commission File No. 001-32886) filed July 11, 2007. |
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10.9† | | Summary of Non-Employee Director Compensation as of March 31, 2011 filed as Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended March 31, 2011 (Commission File No. 001-32886) filed May 5, 2011 and incorporated herein by reference. |
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10.1010.6 | | Seventh Amended and Restated Credit Agreement dated June 30, 2010 among Continental Resources, Inc. as borrower, Union Bank, N.A. as administrative agent, as issuing lender and as swing line lender, and the other lenders party thereto, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed July 7, 2010 and incorporated herein by reference. |
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10.11†10.7 | | EmploymentAmendment No. 1 dated July 26, 2012 to the Seventh Amended and Restated Credit Agreement betweendated June 30, 2010, among Continental Resources, Inc., as borrower, Banner Pipeline Company, L.L.C., as guarantor, Union Bank, N.A., as administrative agent and Eric S. Eissenstat dated
October 14, 2010 filed as Exhibit 10.12 toissuing lender, and the Company’s Form 10-K for the year ended
December 31, 2010 (Commission File No. 001-32886) filed February 25, 2011 and incorporated herein by reference.
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10.12 | | Assignment of Membership Interest dated March 18, 2011 between Harold Hamm and Continental Resources, Inc.other lenders party thereto, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed March 23, 2011August 1, 2012 and incorporated herein by reference. |
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| 10.8† | | First Amendment to the Continental Resources, Inc. 2005 Long-Term Incentive Plan filed February 28, 2013 as Exhibit 10.2 to the Company’s 2012 Form 10-K (Commission File No. 001-32886) and incorporated herein by reference. |
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| 10.9 | | Amendment No. 2 dated April 3, 2013 to the Seventh Amended and Restated Credit Agreement dated June 30, 2010, among Continental Resources, Inc., as borrower, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC as guarantors, Union Bank, N.A., as administrative agent and issuing lender, and the other lenders party thereto, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed April 5, 2013 and incorporated herein by reference.
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| 10.10† | | Continental Resources, Inc. 2013 Long-Term Incentive Plan included as Appendix A to the Company's Definitive Proxy Statement on Schedule 14A (Commission File No. 001-32886) filed April 10, 2013 and incorporated herein by reference. |
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| 10.11† | | Description of cash bonus plan adopted on February 22, 2013 filed as Exhibit 10.1 to the Company's Form 10-Q for the quarter ended March 31, 2013 (Commission File No. 001-32886) filed May 8, 2013 and incorporated herein by reference. |
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| 10.12† | | Form of Employee Restricted Stock Award Agreement under the Continental Resources, Inc. 2013 Long-Term Incentive Plan filed as Exhibit 10.2 to the Company's Current Report on Form 8-K (Commission File No. 001-32886) filed May 24, 2013 and incorporated herein by reference. |
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| 10.13† | | Form of Non-Employee Director Restricted Stock Award Agreement under the Continental Resources, Inc. 2013 Long-Term Incentive Plan filed as Exhibit 10.3 to the Company's Current Report on Form 8-K (Commission File No. 001-32886) filed May 24, 2013 and incorporated herein by reference. |
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| 10.14† | | Summary of Non-Employee Director Compensation Approved as of May 23, 2013 to be effective July 1, 2013 filed as Exhibit 10.6 to the Company's Form 10-Q for the quarter ended June 30, 2013 (Commission File No. 001-32886) filed August 8, 2013 and incorporated herein by reference. |
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| 10.15† | | Continental Resources, Inc. Deferred Compensation Plan filed as Exhibit 10.1 to the Company's Current Report on Form 8-K (Commission File No. 001-32886) filed September 26, 2013 and incorporated herein by reference. |
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| 10.16 | | Amendment No. 4 and Consent dated December 11, 2013 to the Seventh Amended and Restated Credit Agreement dated June 30, 2010, among Continental Resources, Inc., as borrower, Banner Pipeline Company LLC, and CLR Asset Holdings, LLC as guarantors, Union Bank, N.A., as administrative agent and issuing lender, and the other lenders party thereto, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K (Commission File No. 001-32886) filed December 12, 2013 and incorporated herein by reference. |
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| 21* | | Subsidiaries of Continental Resources, Inc. |
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| 23.1* | | Consent of Grant Thornton LLP. |
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| 23.2* | | Consent of Ryder Scott Company, L.P. |
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| 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) |
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| 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) |
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| 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) |
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| 99* | | Report of Ryder Scott Company, L.P., Independent Petroleum Engineers and Geologists |
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| 101.INS** | | XBRL Instance Document |
| |
| 101.SCH** | | XBRL Taxonomy Extension Schema Document |
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| 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 |
*** | Re-filed herewith pursuant to Item 10(d) of Regulation S-K. |
| † | Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K. |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Continental Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
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| CONTINENTAL RESOURCES, INC. |
| |
| By: | | /S/ HAROLD G. HAMM |
| Name: | | Harold G. Hamm |
| Title: | | Chairman of the Board and Chief Executive Officer |
| Date: | | February 24, 201226, 2014 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Continental Resources, Inc. and in the capacities and on the dates indicated.
|
| | | | |
Signature | | Title | | Date |
| | |
/s/ HAROLD G. HAMM Harold G. Hamm
| | Chairman of the Board and (principal executive officer) | | February 24, 201226, 2014 |
| Harold G. Hamm | | | |
| | |
/s/ JOHN D. HART John D. Hart
| | Senior Vice President, Chief Financial Officer and Treasurer (principal (principal financial and accounting officer) | | February 24, 201226, 2014 |
| John D. Hart | | | |
| | |
| /s/ DAVID L. BOREN David L. Boren
| | Director | | February 24, 201226, 2014 |
| David L. Boren | | | | |
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| /s/ ROBERT J. GRANT Robert J. Grant
| | Director | | February 24, 201226, 2014 |
| Robert J. Grant | | | | |
| | |
| /s/ LON MCCAIN Lon McCain
| | Director | | February 24, 201226, 2014 |
| Lon McCain | | | | |
| | |
| /s/ JOHN T. MCNABB II John T. McNabb II
| | Director | | February 24, 201226, 2014 |
| John T. McNabb II | | | | |
| | |
| /s/ MARK E. MONROE Mark E. Monroe
| | Director | | February 24, 201226, 2014 |
| Mark E. Monroe | | | | |
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/s/ H. R. SANDERS, JR.H. R. Sanders, Jr.
EDWARD T. SCHAFER | | Director | | February 24, 201226, 2014 |
| | |
/s/ EDWARD T. SCHAFER
Edward T. Schafer | | Director | | February 24, 2012 |