10-K 1 a201410-k.htm 2014 FORM 10-K 2014 10-K


 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________ 
FORM 10-K
_______________________________ 
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission File Number: 001-32886
_______________________________ 
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
_______________________________ 
Oklahoma
 
73-0767549
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
20 N. Broadway, Oklahoma City, Oklahoma
 
73102
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code: (405) 234-9000
Securities registered pursuant to Section 12(b) of the Act:
Title of class
 
Name of each exchange on 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 Securities Act.    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.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
x
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2014 was approximately $9.1 billion, based upon the closing price of $158.04 per share ($79.02 per share adjusted for September 2014 stock split) as reported by the New York Stock Exchange on such date.
371,906,845 shares of our $0.01 par value common stock were outstanding on February 17, 2015.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of Shareholders to be held in May 2015, 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 
 
 
 
PART I
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
PART II
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
PART III
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
PART IV
 
 
Item 15.





Glossary of Crude Oil and Natural Gas Terms
The terms defined in this section may be 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-Pad 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.
“formation” A layer of rock which has distinct characteristics that differs from nearby rock.
“fracture stimulation” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Also may be referred to as hydraulic fracturing.
"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 an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or 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 horizontally within a specified interval.

i



“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.
“MBoe” One thousand Boe.
“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.
“MMBoe” One million Boe.
“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.
“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.
“pad drilling" or "pad development" 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. Also may be referred to as ECO-Pad drilling or development.
“play” A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.
“productive well” A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
 “prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.
“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
“proved developed reserves” Reserves expected to be recovered through existing wells with existing equipment and operating methods.
“proved undeveloped reserves” or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
“PV-10” When used with respect to crude oil and natural gas reserves, PV-10 represents the estimated future gross revenues to be generated from the production of proved reserves using a 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December, net of estimated production and future development and abandonment costs based on 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 completion technologies.

ii



“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 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 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.
“step-out well” or “step outs” A well drilled beyond the proved boundaries of a field to investigate a possible extension of the field.
“three dimensional (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. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We also use 3D seismic to identify sub-surface hazards to assist in steering, avoiding hazards and determining where to perform enhanced completions.
“unconventional play” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production. In general, unconventional plays require the application of more advanced technology and higher drilling and completion costs to produce relative to conventional plays.
“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“well bore” 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.

iii



Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report and information incorporated by reference in this report include “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. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include, but are not limited to, statements about:
our business and financial strategy;
our future operations;
our crude oil and natural gas reserves and related development plans;
our technology;
crude oil, natural gas liquids, and natural gas prices and differentials;
the timing and amount of future production of crude oil and natural gas and flaring activities;
the amount, nature and timing of capital expenditures;
estimated revenues, expenses and results of operations;
drilling and completing of wells;
competition;
marketing of crude oil and natural gas;
transportation of crude oil, natural gas liquids, and natural gas to markets;
exploitation or property acquisitions and dispositions;
costs of exploiting and developing our properties and conducting other operations;
our financial position;
general economic conditions;
credit markets;
our liquidity and access to capital;
the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;
our future operating results;
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.
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 considers these expectations to be reasonable and based on reasonable assumptions, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors and elsewhere in this report.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. 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.
Except as otherwise required by applicable law, we do not intend, and disclaim any duty, to correct or update any forward-looking statement, whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

iv



Part I
You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “Continental,” “we,” “us,” “our,” “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiaries.
 
Item 1.
Business
General
We are an independent crude oil and natural gas exploration and production company with properties in the North, South and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi River including various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations.
We were originally formed in 1967 to explore for, develop and produce crude oil and natural gas properties. Through the late 1980s, our activities and growth remained focused primarily in Oklahoma. In the late 1980s, we expanded our activity into the North region, where we are now geographically concentrated, with that region comprising approximately 74% of our crude oil and natural gas production and approximately 83% of our crude oil and natural gas revenues for the year ended December 31, 2014. Approximately 69% of our estimated proved reserves as of December 31, 2014 are located in the North region. In 2012 and 2013, we significantly expanded our activity in our South region with our discovery and announcement of the SCOOP play in Oklahoma. Our South region now comprises 26% of our crude oil and natural gas production and 31% of our estimated proved reserves as of December 31, 2014.
We have focused our operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2014, crude oil accounted for approximately 70% of our total production and approximately 85% of our crude oil and natural gas revenues. Crude oil represents approximately 64% of our estimated proved reserves as of December 31, 2014.
We focus our exploration activities in large new or developing crude oil and liquids-rich natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture stimulation) and enhanced recovery technologies 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.
As of December 31, 2014, our estimated proved reserves were 1,351 MMBoe, with estimated proved developed reserves of 502 MMBoe, or 37% of our total estimated proved reserves. For the year ended December 31, 2014, we generated crude oil and natural gas revenues of $4.2 billion and operating cash flows of $3.4 billion. For the year ended December 31, 2014, production averaged 174,189 Boe per day, a 28% increase over average production of 135,919 Boe per day for the year ended December 31, 2013. Average daily production for the quarter ended December 31, 2014 increased 34% to 193,456 Boe per day from 144,254 Boe per day for the quarter ended December 31, 2013.
On August 18, 2014, our Board of Directors declared a 2-for-1 stock split of our common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. All previously reported common stock and earnings per share amounts have been retroactively adjusted throughout this Form 10-K to reflect the stock split.
The table below summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2014, average daily production for the quarter ended December 31, 2014 and the reserve-to-production index in our principal operating areas. 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 Part I, Item 1A. Risk Factors and “Critical Accounting Policies and Estimates” in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition of this report for further discussion of uncertainties inherent in the reserve estimates. 

1



 
 
December 31, 2014
 
Average daily
production for
fourth quarter
2014
(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
 
802,787

 
59.4
%
 
$
13,918

 
1,049

 
115,137

 
59.5
%
 
19.1

Montana Bakken
 
62,817

 
4.6
%
 
1,273

 
274

 
15,646

 
8.1
%
 
11.0

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
49,769

 
3.7
%
 
1,295

 
131

 
9,883

 
5.1
%
 
13.8

Other Red River units
 
15,133

 
1.1
%
 
250

 
123

 
3,376

 
1.7
%
 
12.3

Other
 
4,523

 
0.3
%
 
84

 
5

 
690

 
0.4
%
 
18.0

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
369,742

 
27.4
%
 
5,493

 
146

 
40,403

 
20.9
%
 
25.1

Northwest Cana
 
26,718

 
2.0
%
 
253

 
64

 
3,780

 
2.0
%
 
19.4

Arkoma Woodford
 
10,257

 
0.8
%
 
85

 
58

 
2,318

 
1.2
%
 
12.1

Other
 
9,345

 
0.7
%
 
119

 
250

 
2,223

 
1.1
%
 
11.5

Total
 
1,351,091

 
100.0
%
 
$
22,770

 
2,100

 
193,456

 
100.0
%
 
19.1

 
(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 of approximately $4.3 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 2014 production into estimated proved reserve volumes at December 31, 2014.
Our Business Strategy
Our business strategy 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 this strategy are:
Focus on crude oil. During the 1980s we began to believe the long-term 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, 2014, crude oil comprised 64% of our total proved reserves, 70% of our 2014 annual production, and 85% of our 2014 crude oil and natural gas revenues.
Growth Through Drilling. A substantial portion of our annual capital expenditures are invested in drilling projects and acreage acquisitions. From January 1, 2010 through December 31, 2014, proved crude oil and natural gas reserve additions through extensions and discoveries were 1,376 MMBoe compared to 86 MMBoe of proved reserve acquisitions during that same period.
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 stimulation) and enhanced recovery technologies allows us to economically develop unconventional crude oil and natural gas resource reservoirs, such as the Red River B Dolomite and Bakken formations in our North region and various formations in Oklahoma. Our production from the Bakken, Red River units, SCOOP, Northwest Cana and Arkoma Woodford areas comprised approximately 62,436 MBoe, or 98%, of our total crude oil and natural gas production for the year ended December 31, 2014.
Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 900,808 net undeveloped acres held in the Bakken, Red River units, SCOOP, Northwest Cana and Arkoma Woodford areas, we held 651,240 net undeveloped acres in

2



other crude oil and natural gas plays as of December 31, 2014. 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.
Our Business Strengths
We have a number of strengths we believe will help us successfully execute our business strategy, including the following:
Large Acreage Inventory. We held approximately 1.6 million net undeveloped acres and 1.1 million net developed acres as of December 31, 2014. Approximately 58% of the net undeveloped acres are located within unconventional resource plays in the Bakken, SCOOP, Northwest Cana and Arkoma Woodford areas. As of December 31, 2014, we controlled the largest leasehold positions in the Bakken and SCOOP with approximately 1.2 million net acres and 480,200 net acres under lease in those respective plays. Being an early entrant in Bakken and SCOOP has allowed us to capture significant acreage positions in core parts of the plays.
Experience with Horizontal Drilling and Enhanced Recovery Methods. We have substantial experience with horizontal drilling and enhanced recovery methods and continue to be among industry leaders in the use of new drilling and completion technologies. Our trademarked ECO-Pad drilling concept, which allows for drilling multiple wells from a single pad, is 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 among industry leaders in extending lateral drilling lengths, in some instances up to three miles. Longer laterals are believed to have a positive impact on well productivity and economics. Additionally, we have extensive expertise in the exploration and development of the lower layers or “benches” of the Three Forks formation in the Bakken field, initially targeting the first bench of the Three Forks in mid-2008 followed by completion of wells in the second, third, and fourth benches in 2011, 2012, and 2013, respectively. In 2013 and 2014 we performed pilot density tests designed to determine optimum well spacing and pattern for full field development of the Bakken and Three Forks formations, the results of which are being used to guide future development plans. We have also been among industry leaders in testing enhanced completion technologies involving various combinations of fluid types, proppant volumes and stimulation stage lengths to determine optimal methods for maximizing crude oil recoveries and returns. 
Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2014, we operated properties comprising 83% of our total proved reserves and 81% 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 completion 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 9 senior officers have an average of 31 years of crude oil and natural gas industry experience.
Strong Financial Position. Our corporate credit rating is currently rated as investment grade by Moody’s Investor Services, Inc. and Standard & Poor’s Ratings Services. We have experienced significant growth with our success in the development of the Bakken field and more recently the SCOOP play. Our growth has been matched with a capital sourcing approach which has enabled a strong credit profile. As of February 17, 2015, we have a credit facility with lender commitments totaling $2.5 billion which may be increased up to a total of $4.0 billion to provide additional liquidity if needed to maintain our growth strategy, take advantage of business opportunities, and fund our capital program and commitments. We had $1.9 billion of available borrowing capacity under our credit facility at February 17, 2015 after considering outstanding borrowings and letters of credit. We have no near-term senior note maturities, with our earliest maturity being $200 million due in October 2020. We believe our planned exploration and development activities will be funded substantially from our operating cash flows and credit facility borrowings. Our 2015 capital expenditures budget is reflective of the significant decrease in commodity prices in recent months and has been established based on an expectation of available cash flows from operations and availability under our credit facility. If operating cash flows are materially impacted by a further decline in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability on our credit facility if needed to fund our operations.


3



Crude Oil and Natural Gas Operations
Proved Reserves
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. In 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 Company, L.P (“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 table sets forth our estimated proved crude oil and natural gas reserves and PV-10 by reserve category as of December 31, 2014. The total Standardized Measure of discounted cash flows as of December 31, 2014 is also presented. Our reserve estimates as of December 31, 2014 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 99% of our PV-10, 99% of our proved crude oil reserves, and 95% of our proved natural gas reserves as of December 31, 2014. 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, PV-10 and Standardized Measure at December 31, 2014 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2014 through December 2014, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $94.99 per Bbl for crude oil and $4.35 per MMBtu for natural gas ($84.54 per Bbl for crude oil and $6.06 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
 
333,040

 
939,366

 
489,601

 
$
12,181.3

Proved developed non-producing
 
9,097

 
22,685

 
12,878

 
342.8

Proved undeveloped
 
524,223

 
1,946,335

 
848,612

 
10,246.2

Total proved reserves
 
866,360

 
2,908,386

 
1,351,091

 
$
22,770.3

Standardized Measure (1)
 
 
 
 
 
 
 
$
18,433.0

 
(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 of approximately $4.3 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.

4



The following table provides additional information regarding our proved crude oil and natural gas reserves by region as of December 31, 2014. 
 
 
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
 
220,704

 
350,375

 
279,100

 
433,858

 
538,971

 
523,687

Montana Bakken
 
32,928

 
31,520

 
38,181

 
20,321

 
25,889

 
24,636

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
48,264

 
6,495

 
49,347

 
422

 

 
422

Other Red River units
 
13,310

 
10,938

 
15,133

 

 

 

Other
 
288

 
19,204

 
3,489

 
96

 
5,629

 
1,034

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
24,016

 
366,053

 
85,025

 
69,027

 
1,294,144

 
284,717

Northwest Cana
 
1,036

 
69,396

 
12,602

 
499

 
81,702

 
14,116

Arkoma Woodford
 
11

 
61,475

 
10,257

 

 

 

Other
 
1,580

 
46,595

 
9,345

 

 

 

Total
 
342,137

 
962,051

 
502,479

 
524,223

 
1,946,335

 
848,612

The following table provides information regarding changes in total proved reserves for the periods presented.  
 
 
Year Ended December 31,
MBoe
 
2014
 
2013
 
2012
Proved reserves at beginning of year
 
1,084,125

 
784,677

 
508,438

Revisions of previous estimates
 
(107,949
)
 
(96,054
)
 
4,149

Extensions, discoveries and other additions
 
440,621

 
444,654

 
233,652

Production
 
(63,579
)
 
(49,610
)
 
(35,716
)
Sales of minerals in place
 
(3,227
)
 

 
(7,838
)
Purchases of minerals in place
 
1,100

 
458

 
81,992

Proved reserves at end of year
 
1,351,091

 
1,084,125

 
784,677

Revisions of previous estimates. 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.
In response to the significant decrease in crude oil prices in the latter part of 2014, which has continued into early 2015, we have refined our drilling program and lowered our planned rig count to concentrate our efforts in core areas of the Bakken and SCOOP that provide the opportunity to improve recoveries and rates of return. The refinement of our drilling program contributed to the removal of PUD reserves no longer scheduled to be developed within five years from the date in which they were first booked. One element leading to the removal is an increased emphasis 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. Further, in the SCOOP play we removed certain PUD locations originally planned to be developed with standard lateral drilling lengths in favor of PUDs to be developed with extended length laterals in similar locations. Longer laterals are believed to have a positive impact on well productivity and economics. The combination of these and other factors resulted in the removal of 105 MMBoe of PUD reserves in 2014. These removals were made in accordance with SEC reserve rules and do not necessarily represent the elimination of recoverable hydrocarbons physically in place. In some instances the removed reserves may potentially be developed in the future given the right economic conditions. Commodity price revisions, based on 12-month average SEC prices for 2014, did not have a significant impact on our 2014 reserve revisions, but could potentially have a significant impact on 2015 reserve estimates if the currently depressed pricing environment for crude oil and natural gas persists or worsens.

5



Extensions, discoveries and other additions. These are additions to our proved reserves that result from (i) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling activity in the Bakken field. Proved reserve additions from our drilling activities in the Bakken totaled 222 MMBoe, 276 MMBoe and 185 MMBoe for the years ended December 31, 2014, 2013 and 2012, respectively. Additionally, extensions and discoveries were significantly impacted by successful drilling results in the SCOOP play in 2013 and more so in 2014, resulting in 158 MMBoe and 208 MMBoe of proved reserve additions for 2013 and 2014, respectively. Significant progress continued to be made in 2014 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 2014 drilling activities in the Bakken and SCOOP plays, among others. We expect a significant portion of future reserve additions will come from our major development projects in the Bakken and SCOOP.
Sales of minerals in place. These are reductions to proved reserves that result from the disposition of properties during a period. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions for further discussion of notable dispositions. We may 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 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 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 competitive terms.
Proved Undeveloped Reserves
Our PUD reserves at December 31, 2014 totaled 848,612 MBoe, consisting of 524,223 MBbls of crude oil and 1,946,335 MMcf of natural gas. Substantially all of our PUD reserves at December 31, 2014 are located in the Bakken and SCOOP plays, our most active development areas, with those plays comprising 65% and 34%, respectively, of our total PUD reserves at year-end 2014. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2014.
 
 
Crude Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
Proved undeveloped reserves at December 31, 2013
 
459,158

 
1,309,051

 
677,333

Revisions of previous estimates
 
(66,273
)
 
(266,466
)
 
(110,684
)
Extensions and discoveries
 
204,970

 
1,097,708

 
387,921

Sales of minerals in place
 
(1
)
 
(931
)
 
(156
)
Purchases of minerals in place
 
243

 
313

 
295

Conversion to proved developed reserves
 
(73,874
)
 
(193,340
)
 
(106,097
)
Proved undeveloped reserves at December 31, 2014
 
524,223

 
1,946,335

 
848,612

Revisions of previous estimates. During the year ended December 31, 2014, we removed 306 gross (174 net) PUD locations, which resulted in the removal of 53 MMBo and 315 Bcf (105 MMBoe) of PUD reserves. These removals were due to the decrease in crude oil prices in late 2014 and resulting refinement of our drilling program to place greater emphasis on core areas of the Bakken and SCOOP that provide the opportunity to improve recoveries and rates of return, with increased focus on areas capable of being developed through the use of multi-well pad drilling and extended length laterals. These and other factors contributed to the removal of PUD reserves in certain areas having less attractive rates of return, are less likely to be developed using pad drilling or extended laterals, or are otherwise no longer scheduled to be developed within five years of the date in which they were initially booked.
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 157 MMBo and 196 Bcf (189 MMBoe) in 2014, while SCOOP PUD reserve additions totaled 48 MMBo and 873 Bcf (193 MMBoe). See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2014 drilling activities in the Bakken and SCOOP plays.

6



Conversion to proved developed reserves. In 2014, we developed approximately 21% of our PUD locations and 16% of our PUD reserves booked as of December 31, 2013 through the drilling of 493 gross (264 net) development wells at an aggregate capital cost of approximately $2.0 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. Estimated future development costs relating to the development of PUD reserves are projected to be approximately $2.0 billion in 2015, $2.2 billion in 2016, $2.8 billion in 2017, $2.8 billion in 2018, and $2.4 billion in 2019. These capital projections are reflective of the significant decrease in commodity prices in recent months and have been established based on an expectation of available cash flows from operations and availability under our credit facility. Development of our existing PUD reserves at December 31, 2014 is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be developed within five years of initial booking because of depressed crude oil prices or for other reasons have been removed from our reserves at December 31, 2014. We had no PUD reserves at December 31, 2014 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 reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 99% of our PV-10, 99% of our proved crude oil reserves, and 95% of our proved natural gas reserves as of December 31, 2014 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 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 is 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 reserve estimates. A 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 the 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 semi-annual basis review any internally estimated significant changes to our proved reserves.
Our Vice President—Corporate 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 30 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—Corporate Engineering reports directly to our Senior Vice President—Operations and Resource Development. The reserve estimates are reviewed and approved by the President and Chief Operating Officer and certain other members of senior management.

7



Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2014: 
 
 
Developed acres
 
Undeveloped acres
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
999,847

 
576,265

 
466,243

 
298,606

 
1,466,090

 
874,871

Montana Bakken
 
185,579

 
148,486

 
215,365

 
142,496

 
400,944

 
290,982

Red River units
 
156,624

 
136,302

 

 

 
156,624

 
136,302

Other
 
19,238

 
6,321

 
378,959

 
279,111

 
398,197

 
285,432

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
125,575

 
87,478

 
681,208

 
392,685

 
806,783

 
480,163

Northwest Cana
 
120,809

 
73,217

 
112,022

 
66,760

 
232,831

 
139,977

Arkoma Woodford
 
110,580

 
26,269

 
3,594

 
261

 
114,174

 
26,530

Other
 
104,253

 
49,875

 
240,477

 
184,320

 
344,730

 
234,195

East Region
 

 

 
196,109

 
187,809

 
196,109

 
187,809

Total
 
1,822,505

 
1,104,213

 
2,293,977

 
1,552,048

 
4,116,482

 
2,656,261


The following table sets forth the number of gross and net undeveloped acres as of December 31, 2014 that are scheduled 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 or the leases are renewed. 
 
 
2015
 
2016
 
2017
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
146,902

 
89,593

 
153,746

 
96,622

 
72,789

 
53,705

Montana Bakken
 
71,318

 
43,731

 
60,276

 
44,225

 
48,534

 
33,417

Red River units
 
5,714

 
4,911

 
17,230

 
11,394

 
4,159

 
3,173

Other
 
65,902

 
37,391

 
12,043

 
5,953

 
639

 
256

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
140,180

 
88,276

 
217,200

 
119,204

 
147,451

 
97,420

Northwest Cana
 
29,698

 
15,219

 
40,575

 
29,701

 
27,876

 
15,557

Arkoma Woodford
 

 

 

 

 

 

Other
 
159,266

 
121,600

 
23,421

 
34,195

 
41,108

 
19,657

East Region
 
14,187

 
9,760

 
4,612

 
4,318

 
48,547

 
48,412

Total
 
633,167

 
410,481

 
529,103

 
345,612

 
391,103

 
271,597



8



Drilling Activity
During the three years ended December 31, 2014, we drilled exploratory and development wells as set forth in the table below:
 
 
2014
 
2013
 
2012
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
94

 
70.5

 
75

 
51.5

 
76

 
37.0

Natural gas
 
42

 
8.3

 
40

 
23.7

 
78

 
43.8

Dry holes
 
3

 
1.6

 
3

 
2.1

 
1

 
1.0

Total exploratory wells
 
139

 
80.4

 
118

 
77.3

 
155

 
81.8

Development wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
897

 
290.3

 
734

 
250.9

 
561

 
211.3

Natural gas
 
64

 
16.8

 
26

 
5.4

 
5

 
2.4

Dry holes
 
1

 
1.0

 

 

 
3

 
1.1

Total development wells
 
962

 
308.1

 
760

 
256.3

 
569

 
214.8

Total wells
 
1,101

 
388.5

 
878

 
333.6

 
724

 
296.6

As of December 31, 2014, there were 575 gross (213.2 net) operated and non-operated wells in the process of drilling, completing or waiting on completion.
As of February 17, 2015, we operated 36 rigs on our properties. To align our capital expenditures with lower commodity prices, we plan to decrease our average operated rig count to approximately 34 by the end of first quarter 2015 and average approximately 31 operated rigs for full-year 2015. Our rig activity during 2015 will depend on crude oil and natural gas prices and potential drilling efficiency gains and, accordingly, our rig count may increase or decrease from planned levels. There can be no assurance, however, that rigs will be available to us at an attractive cost. See Part I, Item 1A. Risk Factors—The unavailability or high cost of 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.
Summary of Crude Oil and Natural Gas Properties and Projects
In the following discussion, we review our currently budgeted number of wells and capital expenditures for 2015 in our key operating areas. Our 2015 capital expenditures budget is reflective of the significant decrease in commodity prices in recent months and has been established based on an expectation of available cash flows from operations and availability under our credit facility. If operating cash flows are materially impacted by a further decline in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability on our credit facility if needed to fund our operations. Conversely, higher operating cash flows resulting from an increase in commodity prices could result in increased capital expenditures.
The following table provides information regarding well counts and the budgeted capital we plan to spend on drilling, capital workovers, and facilities in 2015 by operating area.
 
 
2015 Plan
 
 
Gross wells
planned for
drilling
 
Net wells
planned for
drilling
 
Capital
expenditures (1)
(in millions)
 
 
North Region:
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
North Dakota Bakken
 
623

 
186

 
$
1,577

Montana Bakken
 
8

 
5

 
23

Red River units
 
2

 
2

 
44

Other
 
7

 
4

 
56

South Region:
 
 
 
 
 
 
SCOOP
 
157

 
81

 
741

Northwest Cana
 
16

 
5

 
40

Other
 

 

 
2

Total
 
813

 
283

 
$
2,483


9




(1)
The capital expenditures reflected above include amounts for drilling, capital workovers and facilities and exclude budgeted amounts of $180 million for land, $12 million for seismic, and $25 million for vehicles, computers and other equipment. Potential acquisition expenditures are not budgeted.
North Region
Our properties in the North region represented 74% of our PV-10 as of December 31, 2014 and 75% of our average daily Boe production for the fourth quarter of 2014. Our average daily production from such properties was 144,732 Boe per day for the fourth quarter of 2014, an increase of 33% over the comparable 2013 period. Our principal producing properties in the North region are in the Bakken field and the Red River units.
Bakken Field
The Bakken field of North Dakota and Montana is one of the premier crude oil resource plays in the United States. In April 2013, the U.S. Geological Survey released an updated estimate of reserves located in the Bakken field. The assessment projects that the Bakken field contains an estimated mean of 7.4 billion barrels, with a potential of up to 11.4 billion barrels, of undiscovered, technically recoverable crude oil using current technology. In April 2014, the Bakken field reached a milestone with the production of its 1 billionth barrel of crude oil from the formation, with the majority of this production coming in the last three years. According to data published by the U.S. Energy Information Administration for November 2014, North Dakota is the second largest oil producing state in the U.S. due to production growth in the Bakken field.
In 2014, we continued to be a leading producer, leasehold owner and driller in the Bakken field. Our Bakken production averaged 130,783 Boe per day during the fourth quarter of 2014, up 40% from the 2013 fourth quarter. As of December 31, 2014, we controlled the largest leasehold position in the Bakken field with approximately 1.9 million gross (1.2 million net) acres. We are one of the most active drillers in the Bakken, with 21 active operated rigs as of December 31, 2014. Our total proved Bakken field reserves as of December 31, 2014 were 866 MMBoe, an increase of 17% compared to December 31, 2013.
We continued to make significant progress with our development and exploratory drilling programs in the Bakken field during 2014 as summarized in the following North Dakota and Montana discussions.
North Dakota Bakken
Our production and reserve growth in the Bakken field during 2014 came primarily from our activities in North Dakota. Production in North Dakota increased to an average rate of 115,137 Boe per day during the fourth quarter of 2014, up 43% over the 2013 fourth quarter due to the continued success of our drilling activity in the play. In 2014, we completed 860 gross (271 net) wells in North Dakota Bakken. Our North Dakota Bakken properties represented 61% of our PV-10 at December 31, 2014 and 60% of our average daily Boe production for the 2014 fourth quarter. Proved reserves in North Dakota Bakken increased 17% year-over-year to 803 MMBoe as of December 31, 2014, of which 35% represents proved developed reserves. Our inventory of proved undeveloped locations stood at 2,355 gross (1,222 net) wells as of December 31, 2014.
Our 2014 drilling activity in North Dakota focused on (1) developing our derisked areas, (2) expanding the field vertically through drilling in the lower benches of the Three Forks formation and horizontally through step-out exploration drilling, (3) pilot density drilling to determine optimum well spacing and patterns for full field development, and (4) testing various enhanced completion technologies to determine optimal methods for maximizing crude oil recoveries and returns. We successfully achieved our 2014 objectives in each of these areas.
In 2013, we initiated a plan to test different areas across the Bakken field to determine what well density and pattern best maximizes crude oil recoveries and returns. In this effort, in 2013 and 2014 we completed seven density pilot projects designed to test the Middle Bakken and Three Forks One, Two and Three benches across a broad section of our North Dakota leasehold. Three of the projects (Hawkinson, Rollefstad, Tangsrud) tested 1,320 foot inter-well spacing and four projects (Wahpeton, Mack, Lawrence, Hartman) tested 660 foot inter-well spacing. We are utilizing the technical data and production results from these projects to guide our future development of the Bakken and Three Forks reservoirs.
Additionally, in 2014 we embarked on a plan to test various enhanced completion technologies and we are monitoring results throughout our Bakken leasehold seeking to maximize crude oil recoveries and returns. The tests included various combinations of fluid types, increased proppant volumes and shorter stimulation stage lengths. In mid-2014, our assessment was expanded to include industry-wide enhanced completion results. The tests completed to date have yielded encouraging results that show solid improvement in well performance and indicate that increased production rates observed early in the life of tested wells may be sustained in certain areas over a one-year time period, which could translate into higher reserve

10



recoveries per well. We continue to study the implications of applying enhanced completion methods across the play and plan to focus our 2015 North Dakota Bakken capital expenditures in areas where improved recoveries are anticipated. 
In 2015, we plan to invest approximately $1.5 billion to drill and complete 623 gross (186 net) wells in North Dakota Bakken. The 2015 drilling program will focus on drilling development wells in core areas that provide the opportunity to improve recoveries and rates of return. As of December 31, 2014, we had 20 operated rigs drilling in the North Dakota Bakken and plan to average approximately 11 operated rigs throughout 2015. We plan to operate fewer rigs in North Dakota Bakken in 2015 compared to 2014 levels in order to align our 2015 capital expenditures with lower crude oil prices.
Montana Bakken
Our Montana Bakken properties are located primarily within the Elm Coulee field in Richland County, Montana. Montana Bakken represented 6% of our PV-10 as of December 31, 2014 and 8% of our average daily Boe production for the fourth quarter of 2014. Production in Montana increased to an average rate of 15,646 Boe per day during the fourth quarter of 2014, up 21% over the 2013 fourth quarter due to the continued success of our drilling activity in the play. In 2014, we completed 61 gross (41 net) wells in Montana Bakken. Proved reserves in Montana Bakken increased 20% year-over-year to 63 MMBoe as of December 31, 2014, of which 61% represents proved developed reserves. Our inventory of proved undeveloped drilling locations in Montana Bakken as of December 31, 2014 totaled 99 gross (73 net) wells. In 2015, we plan to invest approximately $15 million completing 8 gross (5 net) wells in Montana Bakken.
Red River Units
The Red River units are comprised of nine units located along the Cedar Creek Anticline in North Dakota, South Dakota and Montana that produce crude oil and natural gas from the Red River “B” formation. 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.
All combined, our Red River units and adjacent areas represented 7% of our PV-10 as of December 31, 2014 and 7% of our average daily Boe production for the fourth quarter of 2014. Our average daily production from these legacy properties decreased 8% in the fourth quarter of 2014 compared to the 2013 fourth quarter due to natural declines in production and reduced drilling activity. Proved reserves totaled 65 MMBoe as of December 31, 2014, nearly all of which are proved developed producing reserves. In 2015, we plan to invest approximately $6 million completing 2 gross (2 net) wells in the Red River units.
North Region Marketing Activities
Crude Oil. We utilize a portfolio approach (pipe and rail) to market our crude oil that began in 2008 with our first shipments of crude oil by rail out of the Williston Basin. We plan to continue pursuing a portfolio approach to balance volumes delivered to pipeline and rail market destinations in an effort to maximize net wellhead 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 our North region crude oil will be shipped in this manner in the coming years.
Natural Gas. Field infrastructure build-out continued in the Williston Basin in 2014 as third party midstream gathering and processing companies expanded field gathering and compression facilities, cryogenic processing capacity and natural gas liquids (“NGL”) pipeline and rail capacity to market centers. In 2014, we continued to focus on adhering to our natural gas flaring minimization initiatives. For the year ended December 31, 2014, we delivered approximately 87% of our operated natural gas production in North Dakota Bakken to market, flaring approximately 13% compared to an average of 28% flared by industry peers operating in the play. Of the volumes flared in 2014, approximately 3% of our production was flared for reasons within our control. The other 10% of production that was flared in 2014 came from wells already connected to pipeline gathering systems, indicating that operating issues at downstream gathering and processing facilities owned and operated by third parties necessitated the well-site flaring.
South Region
Our properties in the South region represented 26% of our PV-10 as of December 31, 2014 and 25% of our average daily Boe production for the fourth quarter of 2014. For the 2014 fourth quarter, our average daily production from such properties was 48,724 Boe per day, an increase of 36% from the comparable period in 2013. Our principal producing properties in the South region are located in the SCOOP play.

11



SCOOP
The SCOOP play, discovered by Continental and announced in October 2012, currently extends approximately 120 miles across Garvin, Grady, Stephens, Carter, McClain and Love counties in Oklahoma and contains crude oil and condensate-rich fairways as delineated by numerous industry wells. We are a leading producer, leasehold owner and driller in the SCOOP play. As of December 31, 2014, we controlled the largest leasehold position in SCOOP with approximately 806,800 gross (480,200 net) acres. SCOOP represented 24% of our PV-10 as of December 31, 2014 and 21% of our average daily Boe production for the fourth quarter of 2014. For the year ended December 31, 2014, SCOOP production grew 86% over 2013 due to the continued success of our drilling activity in the play. We completed 151 gross (65 net) wells in SCOOP during 2014. Proved reserves increased 72% year-over-year to 370 MMBoe as of December 31, 2014, of which 23% represents proved developed reserves. Our inventory of proved undeveloped drilling locations in SCOOP as of December 31, 2014 totaled 490 gross (248 net) wells.
Our 2014 drilling program included exploration, step-out and development wells focused on de-risking the play and holding our acreage by production, with an increasing shift toward drilling extended length lateral wells that generate superior economics. The year 2014 was another impactful year for SCOOP as our drilling activities resulted in the vertical expansion of our SCOOP position to include our most recent discovery, the Springer oil play. Located in the heart of our SCOOP acreage, our Springer position supplements our Oklahoma Woodford leasehold and expands our resource potential and inventory in the play. Our SCOOP leasehold has the potential to encounter additional pay from a variety of conventional and potential unconventional reservoirs overlying and underlying the Oklahoma Woodford formation. There are numerous different conventional reservoirs known to produce in the SCOOP area, which have the potential to produce under our SCOOP acreage.
In 2015, we plan to invest approximately $720 million to drill and complete 157 gross (81 net) wells in the SCOOP play. The 2015 drilling program will continue to focus on expanding the known productive extents of the area and de-risking our acreage, while focusing on areas that have the greatest potential to improve recoveries and rates of return. It will also include pilot density projects to determine the optimum well spacing and pattern for full scale development in the future. As of December 31, 2014, we had 23 operated rigs drilling in the SCOOP play and plan to average approximately 16 operated rigs throughout 2015. We plan to operate fewer rigs in SCOOP in 2015 compared to 2014 levels in order to align our 2015 capital expenditures with lower crude oil prices.
Northwest Cana
Our Northwest Cana properties are located in northwestern Oklahoma primarily in Blaine, Dewey and Custer Counties. In recent years, we have undertaken limited drilling activity on our Northwest Cana natural gas properties, choosing instead to allocate capital to areas that generated more attractive rates of return such as the Bakken and SCOOP. Consequently, Northwest Cana represented only 1% of our PV-10 as of December 31, 2014 and 2% of our average daily Boe production for the fourth quarter of 2014. Proved reserves totaled 27 MMBoe as of December 31, 2014, of which 47% represents proved developed reserves. Our inventory of proved undeveloped locations stood at 43 gross (19 net) wells as of December 31, 2014.
In September 2014, we entered into an agreement with a U.S. subsidiary of SK E&S Co. Ltd (“SK”) of South Korea to jointly develop a significant portion of our Northwest Cana natural gas properties, primarily in Blaine and Dewey counties. Under the agreement, we sold a 49.9% interest in approximately 44,000 net acres in the Northwest Cana area of the Anadarko Woodford Shale play, along with interests in 37 producing wells. We received approximately $90 million in cash at closing and SK has committed to pay Continental an additional $270 million to fund, or carry, 50% of our remaining share of future drilling and completion costs over a period of approximately five years.
In 2015, we plan to invest approximately $40 million to drill and complete 16 gross (5 net) wells in Northwest Cana within the area of mutual interest established under the agreement with SK. As of December 31, 2014, we had 4 operated rigs drilling in Northwest Cana and plan to average approximately 4 operated rigs throughout 2015.
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 also plan to deliver a portion of the crude oil 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 2014, 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 are coordinating our well

12



completion operations to coincide with well connections to gathering systems in order to minimize greenhouse gas emissions. We continue to assess downstream transportation options and have developed relationships with downstream transport and end-use customers for possible future portfolio pricing benefits.
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, 2014, 2013 and 2012 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2014: 
 
 
Year ended December 31,
 
 
2014
 
2013
 
2012
Net production volumes:
 
 
 
 
 
 
Crude oil (MBbls) (1)
 
 
 
 
 
 
North Dakota Bakken
 
30,917

 
23,513

 
15,936

SCOOP
 
3,652

 
2,004

 
478

Total Company
 
44,530

 
34,989

 
25,070

Natural gas (MMcf)
 
 
 
 
 
 
North Dakota Bakken
 
33,610

 
26,783

 
16,454

SCOOP
 
55,017

 
29,438

 
7,060

Total Company
 
114,295

 
87,730

 
63,875

Crude oil equivalents (MBoe)
 
 
 
 
 
 
North Dakota Bakken
 
36,518

 
27,977

 
18,679

SCOOP
 
12,822

 
6,910

 
1,654

Total Company
 
63,579

 
49,610

 
35,716

Average sales prices: (2)
 
 
 
 
 
 
Crude oil ($/Bbl)
 
 
 
 
 
 
North Dakota Bakken
 
$
80.22

 
$
89.45

 
$
84.50

SCOOP
 
87.58

 
95.63

 
89.37

Total Company
 
81.26

 
89.93

 
84.59

Natural gas ($/Mcf)
 
 
 
 
 
 
North Dakota Bakken (3)
 
$
6.63

 
$
5.94

 
$
5.20

SCOOP (3)
 
5.23

 
5.25

 
3.82

Total Company (3)
 
5.40

 
4.87

 
3.73

Crude oil equivalents ($/Boe)
 
 
 
 
 
 
North Dakota Bakken (3)
 
$
73.96

 
$
80.87

 
$
76.64

SCOOP (3)
 
47.35

 
50.08

 
33.01

Total Company (3)
 
66.53

 
72.04

 
65.99

Average costs per Boe: (2)
 
 
 
 
 
 
Production expenses ($/Boe)
 
 
 
 
 
 
North Dakota Bakken
 
$
5.67

 
$
5.50

 
$
4.31

SCOOP
 
1.13

 
0.99

 
1.02

Total Company
 
5.58

 
5.69

 
5.49

Production taxes and other expenses ($/Boe) (3)
 
$
5.54

 
$
6.02

 
$
5.58

General and administrative expenses ($/Boe) (4)
 
$
2.92

 
$
2.91

 
$
3.42

DD&A expense ($/Boe)
 
$
21.51

 
$
19.47

 
$
19.44


(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 marketing disruptions or we have sold crude oil from inventory. Crude oil sales volumes were 408 MBbls less than production volumes for 2014, 4 MBbls less than production volumes for 2013, and 112 MBbls less than production volumes for 2012.

13



(2)
Average sales prices and per unit costs have been calculated using sales volumes and exclude any effect of derivative transactions.
(3)
Prior to 2014 we presented charges related to natural gas transportation and processing in the caption "Production taxes and other expenses" in our consolidated statements of comprehensive income. Effective January 1, 2014, such charges are netted within "Crude oil and natural gas sales". Average sales prices and per unit costs for 2013 and 2012 have been adjusted, as applicable, to conform to the current year presentation. Reclassified amounts for the total Company amounted to $33.3 million ($0.67 per Boe) for 2013 and $29.9 million ($0.84 per Boe) for 2012.
(4)
General and administrative expense ($/Boe) includes non-cash equity compensation expenses of $0.86 per Boe, $0.80 per Boe, and $0.82 per Boe for 2014, 2013 and 2012, respectively, and corporate relocation expenses of $0.04 per Boe and $0.22 per Boe for 2013 and 2012, respectively.
The following table sets forth information regarding our average daily production by region during the fourth quarter of 2014: 
 
 
Fourth Quarter 2014 Daily Production
 
 
Crude Oil
(Bbls per day)
 
Natural Gas
(Mcf per day)
 
Total
(Boe per day)
North Region:
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
North Dakota Bakken
 
96,220

 
113,500

 
115,137

Montana Bakken
 
13,758

 
11,327

 
15,646

Red River units
 
 
 
 
 
 
Cedar Hills
 
9,504

 
2,271

 
9,883

Other Red River units
 
2,941

 
2,610

 
3,376

Other
 
145

 
3,272

 
690

South Region:
 
 
 
 
 
 
SCOOP
 
13,130

 
163,643

 
40,403

Northwest Cana
 
341

 
20,635

 
3,780

Arkoma Woodford
 
4

 
13,886

 
2,318

Other
 
929

 
7,763

 
2,223

Total
 
136,972

 
338,907

 
193,456

Productive Wells
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, 2014. One or more completions in the same well bore are counted as one well.
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total Wells
 
 
Gross    
 
Net    
 
Gross    
 
Net    
 
Gross    
 
Net    
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
3,117

 
1,049

 
1

 

 
3,118

 
1,049

Montana Bakken
 
421

 
273

 
2

 
1

 
423

 
274

Red River units
 
 
 
 
 
 
 
 
 
 
 


Cedar Hills
 
137

 
131

 

 

 
137

 
131

Other Red River units
 
137

 
123

 

 

 
137

 
123

Other
 
1

 
1

 
16

 
4

 
17

 
5

South Region:
 
 
 
 
 
 
 
 
 
 
 

SCOOP
 
100

 
65

 
199

 
81

 
299

 
146

Northwest Cana
 
4

 
3

 
170

 
61

 
174

 
64

Arkoma Woodford
 
1

 

 
390

 
58

 
391

 
58

Other
 
199

 
153

 
195

 
97

 
394

 
250

Total
 
4,117

 
1,798

 
973

 
302

 
5,090

 
2,100


14



Title to Properties
As is customary in the crude oil and natural gas industry, upon initiation of fee leasing of undeveloped leasehold which does not have associated proved 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 a property, we may procure a title opinion from external legal counsel or perform curative work to satisfy requirements pertaining to material title defects. We may choose not to commence drilling operations on a property until we have cured material title defects as to the Company's interest on such property.
We have procured and cured title opinions on substantially all of our producing properties and believe we have defensible title to our producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. Our crude oil and natural gas properties are subject to customary royalty and other interests 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, with the remaining balance of our production being transported by truck or rail. Where directly marketed crude oil is transported by truck, it 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 purchaser’s truck and the sale is complete at that point.
We have a strategic mix of gas transport, processing and sales arrangements for our natural gas production. A majority of our natural gas production is sold at the wellhead, with the remainder being sold at various 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. 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. We continue to develop relationships and have potential future contracts with end-use customers including utilities, industrial and liquefied natural gas exporters.
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, see Part 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 year ended December 31, 2014, sales to Marathon Crude Oil Company and PBF Holding Company LLC accounted for approximately 14% and 11%, respectively, of our total crude oil and natural gas revenues. No other purchasers accounted for more than 10% of our total crude oil and natural gas revenues for 2014. We believe the loss of any single 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.
Competition
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.

15



Regulation of the Crude Oil and Natural Gas Industry
Our operations are conducted onshore almost entirely 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 interpretations affecting our industry have been and are pervasive and are continuously reviewed by legislators and regulators, resulting in 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. These requirements may have a significant effect on the exploration, development, production and sale of crude oil and natural gas and 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 us 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 enacted, 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 us in a manner materially different than they would affect our similarly situated competitors.
The following is a discussion of significant laws and regulations that may affect us in the areas in which we operate.
Regulation of sales and transportation of crude oil and natural gas liquids
Sales of crude oil and natural gas liquids or condensate in the United States are not currently subject to price controls and are made at negotiated prices. Nevertheless, the U.S. Congress could enact price controls in the future. The United States regulates the exportation of petroleum and petroleum products, and these regulations could restrict the markets for these commodities and thus affect sales prices. Regulations restricting the exportation of domestically produced petroleum products date back to the 1970s. Certain U.S. lawmakers are considering initiating legislation aimed at amending or removing the export restrictions. Additionally, the President of the United States could lift the export restrictions by executive order and the Bureau of Industry and Security of the U.S. Department of Commerce could issue crude oil export licenses. At this time, the enactment of any such legislation or actions and the potential impact on commodity markets and sales prices is uncertain.
With regard to our physical sales of crude oil and any 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—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 and the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. In general, 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 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 we pay are generally applicable to all comparable shippers, we believe the regulation of intrastate transportation rates will not affect us in a way that materially differs from the effect on our similarly situated competitors.
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. We believe we generally will have access to crude oil pipeline transportation services to the same extent as our similarly situated competitors.
We transport a portion of the operated crude oil production from our North region to market centers using rail transportation facilities owned and operated by third parties, with approximately 36% of such production being shipped by rail in December 2014. 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 U.S. DOT, the Occupational Safety and Health Administration, as well as other federal regulatory agencies.

16



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 2008, the U.S. Congress passed the Rail Safety and Improvement Act, which implemented regulations governing different areas related to railroad safety. More recently, the FRA and PHMSA have undertaken several actions over the past year to enhance the safe transport of crude oil, including but not limited to: issuing an order requiring proper testing, classification and handling of crude oil as a hazardous material; requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas; issuing safety advisories, alerts, emergency orders and regulatory updates; conducting special unannounced inspections; moving forward with rulemaking to enhance tank car standards for certain trains carrying crude oil and ethanol; and reaching agreement with the railroad industry on a series of voluntary actions they can take to improve safety. Notably, in May 2014 the U.S. DOT issued an order requiring all railroads operating trains containing large amounts of Bakken crude oil to notify state emergency response commissions about the operation of such trains through their states. The order requires each railroad operating trains containing more than 1,000,000 gallons of Bakken crude oil, or approximately 35 tank cars, in a particular state to provide the state with notification regarding the volumes of Bakken crude oil being transported, frequencies of anticipated train traffic and the route through which Bakken crude oil will be transported.  Also in May 2014, the FRA and PHMSA issued a safety advisory to the rail industry strongly recommending the use of tank cars with the highest level of integrity in their fleet when transporting Bakken crude oil. In August 2014, PHMSA issued a Notice of Proposed Rulemaking proposing, among other things, additional requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, and a requirement that older DOT-111 tank cars be phased out by as early as October 1, 2017 if they are not retrofitted to comply with new tank car design standards. The final rule is expected in the first half of 2015. In conjunction with the proposed rule, PHMSA published an Advanced Notice of Proposed Rulemaking related to potential revisions to its regulations to expand the applicability of comprehensive oil spill response plans to certain trains based on the thresholds of crude oil that apply to an entire train.

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 market centers throughout the United States, 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.
At the state level, in December 2014 the North Dakota Industrial Commission ("NDIC") implemented new rules designed to reduce the potential flammability of crude oil produced from the Bakken petroleum system (the Bakken, Three Forks, and Sanish Pool formations) before it is loaded on railcars and transported. The rules, which take effect on April 1, 2015, outline a series of standards for pressure and temperature for production facilities to follow in order to separate certain liquids and gases from the crude oil prior to transport. The regulations are designed to leave the crude oil with a vapor pressure of no more than 13.7 pounds per square inch ("psi") compared to national standards that require 14.7 psi. While the new rules could cause our cost of doing business in North Dakota to increase, we do not expect these changes to have a material impact on us nor will they affect us in a way that materially differs from our similarly situated competitors.
Regulation of sales and transportation of natural 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. 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 to 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

17



sale of transportation and storage services. The 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 pro-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 similarly situated natural gas producers.
With regard to our physical sales of natural gas and any 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—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 generally 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, equitable 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 may have on us, but the natural gas industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory 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 intrastate natural gas transportation in states in which we operate and ship natural gas on an intrastate basis will not affect us in a way that materially differs from our similarly situated competitors.
Regulation of production
The production of crude oil and natural gas is subject to regulation under a wide range of federal, state and local statutes, rules, orders 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, 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, as well as regulations that generally limit or prohibit the venting or flaring of natural gas. 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 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 similarly situated competitors in the crude oil and natural gas industry are generally subject to the same statutes, regulatory requirements and restrictions.
Other federal laws and regulations 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. The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules and regulations to implement the new legislation. Although the CFTC has issued final regulations to implement significant aspects of the legislation, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

18



In November 2013, the CFTC proposed rules establishing position limits with respect to certain futures and option contracts and equivalent swaps, subject to exceptions for certain bona fide hedging. As these new position limit rules are not yet final, the impact of these provisions on us is uncertain at this time.
Pursuant to the Dodd-Frank Act, mandatory clearing is now required for all market participants, unless an exception is available. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet required the clearing of any other classes of swaps, including physical commodity swaps, and the trade execution requirement does not apply to swaps not subject to a clearing mandate. Although we expect to qualify for the end-user exception from the clearing requirement for our swaps entered into to hedge our commercial risks, the application of the mandatory clearing requirements 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. 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 be required to clear such transactions or execute them on a derivatives contract market or swap execution facility. The ultimate effect of the proposed rules and any additional regulations on our business is uncertain.
In addition, certain banking regulators and the CFTC have proposed rules to establish minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce our liquidity and cash available for capital expenditures and could reduce our ability to manage commodity price volatility and the volatility in our cash flows.
In addition to the CFTC’s swap regulations, certain foreign jurisdictions 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 some 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, 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. 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, could have an adverse effect on our ability to hedge risks associated with our business.
Additionally, the SEC had adopted rules as required under the Dodd-Frank Act requiring 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 has stated it plans to issue a revised proposal, the timing of which is uncertain.
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 significant changes to the statutory framework affecting the energy industry. Among other matters, EPAct 2005 amended the NGA to add an anti-market manipulation provision making 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.
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

19



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 under the 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 in November 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 or 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 a court to 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. Knowing or willful violations of the Commodity Exchange Act may also lead to a felony conviction.
Additional proposals and proceedings that may 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 these or the above laws and regulations may have on our crude oil and natural gas operations. We do not believe we will be affected by any such action materially differently than our similarly situated competitors.
Environmental, health and safety regulation
General. We 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 to conduct exploration, drilling and production operations;
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;
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and
impose substantial liabilities for pollution resulting from drilling and production operations.
These laws and regulations may also restrict the rate of crude oil and natural gas production below a rate otherwise 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. We are committed to conducting our operations in a manner that protects the health, safety and welfare of the public, our 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 and safety risks and the 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 and safety initiatives.

20



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 engage in ongoing training of 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 various types of emergencies affecting our personnel, facilities or the environment.
One ongoing focus of our HSS&E initiatives is the reduction of air emissions produced from our operations, particularly with respect to flaring 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. North Dakota statutes permit flaring of natural gas from a well that has not been connected to a gas gathering line for a period of one year from the date of a well's first production. After one year, a producer is required to either cap the well, connect it to a gas gathering line, find acceptable alternative uses for a percentage of the flared gas, or apply to the NDIC for a written exemption for any future flaring. If an unconnected well is not capped, exempted, or utilizing an acceptable alternative for capturing a percentage of the flared gas, then the producer is required to pay royalties and production taxes on the value of flared gas, as determined by the NDIC. Further, NDIC rules for new drilling permit applications also require the submission of gas capture plans that address measures taken by operators to capture and not flare produced gas, regardless of whether it has been or will be connected within the first year of production. While the NDIC has thus far generally accepted our gas capture plans submitted with applications for drilling permits, and our proposed methods for valuing and calculating taxes and royalties on flared gas, the requirements for obtaining permits to drill, exemptions from post-year flaring restrictions, and determinations of volumes and value for royalty calculation on flared gas remain uncertain and subject to change.
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. We make efforts to coordinate our well completion operations to coincide with well connections to gathering systems in order to minimize flaring. 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.
For the year ended December 31, 2014, we delivered approximately 87% of our operated natural gas production in North Dakota Bakken to market, flaring approximately 13% compared to 11% in 2013, 15% in 2012 and 19% in 2011. Of the volumes flared in 2014, approximately 3% of our production was flared for reasons within our control. The other 10% of production flared in 2014 came from wells already connected to pipeline gathering systems, indicating that operating issues at downstream gathering and processing facilities owned and operated by third parties necessitated the well-site flaring.
We believe maintaining our low level of flaring is a notable accomplishment given the significant increase in our natural gas production in the Bakken field, including areas with limited gas gathering 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 NDIC, our industry as a whole flared approximately 28% of produced natural gas volumes in the state during 2014. We are a participant in the NDIC’s Flaring Reduction Task Force and are 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 the Montana Bakken, we flared approximately 10% (5% within our control) of the natural gas produced from our operated well sites in 2014. 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. 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 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 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

21



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 Department 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 Endangered Species Act and comparable state statutes, which afford protections to certain plant and animal species; (xi) the Migratory Bird Treaty Act, which imposes certain restrictions for the protection of migratory birds; (xii) the federal Occupational Safety and Health Act and comparable state statutes, which require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations, and (xiii) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material.
Air emissions and climate change. Federal, state and local laws and regulations are 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.” In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for the greenhouse gas emissions also will be required to meet “best available control technology” standards established on a case-by-case basis. We currently do not have any facilities that are required to adhere to the PSD or Title V permit requirements. EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
In addition, the EPA has adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. More recently, in January 2015, the Obama Administration announced the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45% from 2012 levels by 2025.
In April 2012, the EPA issued final rules establishing new air emission controls for crude oil and natural gas production and natural gas processing operations under the New Source Performance Standards and National Standards for Emission of Hazardous Air Pollutants programs. With regard to production activities, the rules require, among other things, the reduction of volatile organic compound (“VOCs”) emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must use reduced emission completions or “green completions.” The rules also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The rules are designed to limit emissions of VOC, sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oil and natural gas production facilities, and natural gas transmission compressor stations. We have modified our operations and well equipment as needed to comply with these rules. Ongoing compliance with the rules is not expected to affect us in a way that materially differs from our similarly situated competitors.
While Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal legislation, a number of state and regional efforts have emerged that are aimed at tracking and reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gas. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce

22



emissions of greenhouse gases associated with our operations. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the oil and natural gas we produce. Finally, it should be noted that 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, floods and other climatic events. If any such effects from such causes were to occur, they could have an adverse effect on our exploration and production operations.
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. Recently there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and to cause earthquakes. As a result, several federal agencies are studying the environmental risks with respect to hydraulic fracturing, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.
Also at the federal level, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014. In May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. Further, the EPA has announced its intention to propose regulations under the CWA sometime in 2015 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. Moreover, the EPA is conducting a study of the potential impacts of hydraulic fracturing activities on water resources and a draft final report is anticipated sometime in 2015 for peer review and public comment. The results of this study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Finally, the U.S. Department of Interior issued proposed rules in May 2013 to update existing regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. A final version of these rules may be adopted in 2015.
At the state level, several states, including states in which we operate, have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In certain areas of the United States, new drilling permits for hydraulic fracturing have 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, hydraulic fracturing processes in areas in which we operate 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 our failure to comply, 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 such federal or state legislation is enacted into law.
Waste water disposal. Underground injection control wells are a predominant method for disposing of waste water from oil and gas activities. In response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. In response to these concerns,

23



regulators in some states are considering additional requirements related to seismic safety. The EPA's current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. We cannot predict the EPA's future actions in this regard. The introduction of new environmental initiatives and regulations related to waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection control wells which could cause us to delay, curtail or discontinue our exploration and development plans. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil and gas producers and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations to any greater degree than other similarly situated competitors.
Employees
As of December 31, 2014, we employed 1,188 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 is 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 Business Conduct and Ethics and the charters for various committees of our Board of Directors, please see our website. We intend to disclose amendments to, or waivers from, our Code of Business Conduct and 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 is www.sec.gov.
Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.

24



Item 1A.
Risk Factors
You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our securities. 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 our securities 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 the business 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, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.
A substantial or extended decline in crude oil and natural gas prices would adversely affect our business, financial condition, results of operations or cash flows 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, capital budget 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, as evidenced by the significant decrease in crude oil prices in the third and fourth quarters of 2014, and which continued into early 2015. Historically, the markets for crude oil and natural gas have been volatile; for example, the NYMEX West Texas Intermediate crude oil and Henry Hub natural gas spot prices ranged from $53.45 to $107.95 per barrel and $2.74 to $8.15 per MMBtu, respectively, during 2014. Crude oil and natural gas prices are likely to remain volatile in 2015.
In the fourth quarter of 2014, following a decrease in crude oil prices and related increase in the fair value of our derivative assets, substantially all of our outstanding crude oil derivative contracts for periods subsequent to December 31, 2014 were settled prior to the expiration of their contractual maturities, resulting in the receipt of cash proceeds totaling approximately $433 million. Consequently, our crude oil production and sales for 2015 and beyond are currently unhedged and directly exposed to continued volatility in crude oil market prices, whether favorable or unfavorable.
The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
worldwide, domestic and regional economic conditions impacting the global supply of and demand for crude oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries and other producing nations;
the level and effect of trading in commodity futures markets;
the price and quantity of imports of foreign crude oil;
the potential export of crude oil or liquefied natural gas from the United States;
military and 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 fundamentals;
the availability, proximity and capacity of transportation, 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 cost of transporting, processing, and marketing crude oil and natural gas;
adverse weather conditions and natural disasters;
technological advances affecting energy consumption;
the effect of worldwide energy conservation and environmental protection efforts; and
the price and availability of alternative fuels or other energy sources.

25



Sustained declines in crude oil and natural gas prices may: (i) reduce our cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; (ii) limit our ability to borrow money or raise additional capital; and (iii) reduce the amount of crude oil and natural gas we can economically produce.
Substantial, extended decreases in crude oil and natural gas prices may cause us to delay or postpone a significant portion of our exploration, development and exploitation projects or may render such projects uneconomic. This may result in significant downward adjustments to our estimated proved reserves and may lead to a downgrade or other negative rating action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital and our ability to access capital markets, increase our costs under our credit facility, and limit our ability to execute aspects of our business plans. 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, cash flows, liquidity or ability to finance planned capital expenditures and commitments.
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.
Our operations are geographically concentrated in the North region, with that region comprising approximately 74% of our crude oil and natural gas production and approximately 83% of our crude oil and natural gas revenues for the year ended December 31, 2014. Additionally, as of December 31, 2014 approximately 69% of our estimated proved reserves were located in the North region. Our principal producing properties in the North region are located in the Bakken field of North Dakota and Montana.
Because of this geographic concentration, the success and profitability of our operations may be disproportionately exposed to regional factors relative to our competitors that have more geographically dispersed operations. These factors include, among others: (i) 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 rail transportation capacity constraints; (ii) the availability of rigs, equipment, oil field services, supplies, and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the North region may be adversely affected by severe weather events such as floods and blizzards, 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 our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the 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, results of operations and cash flows.
Volatility in the financial markets or in global economic factors could adversely impact our business and financial condition.
United States and global economies may experience periods of turmoil and volatility from time to time, which may be characterized by diminished liquidity and credit availability, inability to access capital markets, high unemployment, unstable consumer confidence and diminished consumer spending. In recent periods, there has been significant downward pressure on oil prices, and a continuation of that trend could continue or exacerbate that pressure. This would negatively impact our revenues, margins, profitability, operating cash flows, liquidity and financial condition. Such weakness or uncertainty could also cause our natural gas hedging arrangements or future crude oil hedges, if any, 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 credit facility and proceeds from 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 result in our inability to obtain needed capital on acceptable terms or at all and may increase our cost of financing. We have a credit facility with lender commitments totaling $2.5 billion, which may be increased up to a total of $4.0 billion upon agreement with participating lenders. In the future, we may not be able to access adequate funding under our credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments as required under the credit facility. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or 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, fund our capital program and commitments, 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 of the above risks occur, they could have a material adverse effect on our financial condition, results of operations and cash flows.

26



Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on acceptable terms, which could lead to a decline in our crude oil and natural gas reserves, production and revenues. In addition, funding our capital expenditures with additional debt will increase our leverage and doing so with equity securities may result in dilution that reduces the value of your stock.
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 2014, we invested approximately $5.02 billion in our capital program, inclusive of property acquisitions. We have budgeted $2.70 billion for capital expenditures in 2015 (excluding acquisitions which are not budgeted) of which $2.48 billion is allocated for drilling, capital workovers and facilities. Our 2015 capital expenditures are substantially lower than such expenditures in 2014 as a result of lower commodity prices. We may find that additional reductions are prudent depending on market conditions.
Historically, our capital expenditures have been financed with cash generated by operations, borrowings under our credit facility and proceeds from 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 others, changes in commodity prices, available cash flows, lack of access to capital, 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.
Our cash flows from operations and access to capital are subject to a number of variables, 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 lenders to extend credit or of participants in the capital markets to invest in our senior notes or equity securities.
If revenues or our ability to borrow decrease significantly, we may have limited ability to obtain the capital necessary to sustain our operations at planned levels. If cash generated by operations or cash available under our 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, results of operations, and cash flows and our ability to achieve our growth plans.
We intend to finance future capital expenditures primarily through cash flows from operations and borrowings under our 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 will require a portion of our cash flows from operations to 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.
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.

27



Further, many factors may curtail, delay or cancel scheduled drilling projects, including but not limited to:
abnormal pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment or qualified personnel;
shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;
mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or train derailments;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
decreases in crude oil and natural gas prices;
limited availability of financing with acceptable terms;
title problems;
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 us or by third party service providers;
limitations in infrastructure, including transportation, processing and refining capacity, or markets for crude oil and natural gas; and
delays imposed by or resulting from compliance with regulatory requirements including permitting.
Additionally, severe weather conditions and natural disasters such as flooding, tornadoes, blizzards and ice storms affecting the areas in which we operate, including our corporate headquarters, could have a material adverse effect on our operations. The consequences of such events may include the evacuation of personnel, damage to drilling rigs or pipeline and rail transportation facilities, an inability to access well sites, destruction of information and communication systems, and the disruption of administrative and management processes, any of which could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations and cash flows
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, in particular due to the recent significant decline in commodity prices.
The process of estimating crude oil and natural gas reserves is 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. See Part 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, 2014.
In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. Our booked proved undeveloped reserves must be developed within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame could result in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period.
We must also analyze available geological, geophysical, production and engineering data in preparing reserve estimates. The extent, quality and reliability of this data can 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.
The prices used in calculating our estimated proved reserves are, in accordance with SEC requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ended December 31, 2014, average prices used to calculate our estimated proved reserves were $94.99 per Bbl for crude oil and $4.35 per MMBtu for natural gas ($84.54 per Bbl for crude oil and $6.06 per Mcf for natural gas adjusted for location and quality differentials). Commodity prices declined significantly in the fourth quarter of 2014 and if such prices

28



do not increase significantly, our future calculations of estimated proved reserves will be based on lower commodity prices which could result in our having to remove non-economic reserves from our proved reserves in future periods. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were decreased by $40.00 per Bbl for crude oil and $1.00 per Mcf for natural gas, thereby approximating the pricing environment existing in February 2015, our proved reserves at December 31, 2014 could decrease by approximately 10%.
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, 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 and, in particular, may be reduced due to the recent significant decline in commodity prices.
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:
the actual prices we receive for sales of crude oil and natural gas;
the actual cost and timing of development and production expenditures;
the timing and amount of actual production; 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.
At December 31, 2014, the PV-10 value of our proved reserves totaled approximately $22.8 billion. The average prices used to estimate our proved reserves and PV-10 at December 31, 2014, as calculated in accordance with SEC rules, were $94.99 per Bbl for crude oil and $4.35 per MMBtu for natural gas ($84.54 per Bbl for crude oil and $6.06 per Mcf for natural gas adjusted for location and quality differentials). Actual future prices may materially differ from those used in our year-end estimates. If crude oil prices decline by $10.00 per barrel from those used in our year-end estimates, our PV-10 as of December 31, 2014 could decrease approximately $3.2 billion, or 14%. If natural gas prices decline by $1.00 per Mcf from those used in our year-end estimates, our PV-10 as of December 31, 2014 could decrease approximately $1.7 billion, or 8%.
Commodity prices have decreased significantly in recent months. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were decreased by $40.00 per Bbl for crude oil and $1.00 per Mcf for natural gas, thereby approximating the pricing environment existing in February 2015, our PV-10 at December 31, 2014 could decrease by approximately $13.8 billion, or 61%.
We may be required to write down the carrying values of our crude oil and natural gas properties if crude oil prices remain at their currently low levels or decline further.
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, prices, 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 results in a non-cash charge to earnings. We have incurred impairment charges in the past and may incur additional impairment charges in the future, particularly if crude oil prices remain at their currently low levels or decline further, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

29



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 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.
In the regions in which we operate, there have historically been shortages of drilling rigs, equipment, supplies, personnel or oilfield services, including key components used in fracture stimulation processes such as water and proppants, as well as high costs associated with these critical components of our operations. Such shortages or costs could delay the execution of our drilling plans 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, results of operations and cash flows.
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 under-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;
adverse weather conditions and natural disasters; and
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
injury or loss of life;
damage to or 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 we face are generally not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

30



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 and develop 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 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 is subject to 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 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 sufficient quantities to achieve an economic return. 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. Currently low crude oil prices, reduced capital spending and numerous other factors, many of which are beyond our control, could result in our failure to establish production on undeveloped acreage, and, if 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 66% of our total net undeveloped acreage at December 31, 2014. At that date, we had leases representing 410,481 net acres expiring in 2015, 345,612 net acres expiring in 2016, and 271,597 net acres expiring in 2017. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Our proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2014, approximately 63% of our total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove to be accurate. Our reserve report at December 31, 2014 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $12.2 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any proved undeveloped reserves not developed within this five-year time frame. A removal of such reserves could adversely affect our operations. In 2014, 105 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates due to various factors, including removals associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.
Our business depends on crude oil and natural gas transportation, processing and refining facilities, most of which are owned by third parties, and on the availability of rail 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 and processing and refining facilities owned by third parties. The inadequacy 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, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our

31



production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.
The disruption of transportation, processing or refining facilities due to labor disputes, maintenance, civil disturbances, public protests, terrorist attacks, cyber attacks, adverse weather, natural disasters, changes in tax and energy policies, federal and state regulatory developments, changes in supply and demand, equipment failures or accidents, including pipeline ruptures or train derailments, and general economic conditions could negatively impact our ability to market and deliver our products or achieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such facilities would be restored or what prices would 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.
We transport a portion of the operated crude oil production from our North region to market centers using rail transportation facilities owned and operated by third parties, with approximately 36% of such production being shipped by rail in December 2014. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Regulation of sales and transportation of crude oil and natural gas liquids for a discussion of regulations that could potentially impact the transportation of crude oil by rail. The introduction of regulations, including voluntary measures adopted by the railroad industry, 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 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.
Our business depends on the availability of water and the ability to dispose of water. Limitations or restrictions on our ability to obtain or dispose of 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, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection control wells.
In addition, concerns have been raised about the potential for earthquakes to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of water necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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. For instance, one of our prospects in Texas in the early stages of exploration and development has not yielded sufficient reserves and production to achieve a satisfactory economic return, which resulted in $58 million of proved property impairments and $92 million of unproved property impairments being recognized for the prospect in 2014.

32



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 federal, state and local laws and regulations, including those governing environmental protection, the occupational health and safety aspects of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species. 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. 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. Environmental regulations may restrict 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 liabilities for pollution resulting from our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenues.
Failure to comply with laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, or the issuance of orders or judgments limiting or enjoining future operations. 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. 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 personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
Moreover, our costs of compliance with existing laws could be substantial and may increase or unforeseen liabilities could be imposed if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
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.
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. We currently do not have any facilities that are required to adhere to the PSD or Title V permit requirements. EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
In addition, the EPA has adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. More recently, in January 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45% from 2012 levels by 2025.
While Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs. Most of these cap-and-trade programs require 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 install new equipment to reduce emissions of greenhouse gases 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, results of operations and cash flows.

33



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 or 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.
Hydraulic fracturing is 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. Recently there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and increase the potential for earthquakes. As a result, several federal and state agencies are considering legislation that would increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014. In addition, in May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. Further, the EPA has announced its intention to propose regulations under the CWA sometime in 2015 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. The EPA is also conducting a study of the potential environmental impacts of hydraulic fracturing on water resources and a draft final report is anticipated sometime in 2015 for peer review and public comment. The results of this study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Further, the Bureau of Land Management issued a revised proposed rule in May 2013 that would require public disclosure of chemicals used in hydraulic fracturing operations, and impose other operational requirements for all hydraulic fracturing operations on federal lands, including Native American trust lands. As of December 31, 2014, we held approximately 209,800 net undeveloped acres on federal land, representing approximately 14% of our total net undeveloped acres.

At the state level, several states, including states in which we operate, have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. 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. This would have a material adverse effect on our business and would impair our ability to implement our growth plans.
Proposed legislation and regulations under consideration could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.
Changes to existing laws or regulations, new laws or regulations, or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products. Similarly, 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. If such legislation, regulations or other requirements are adopted, they could result in, among other items, additional limitations and restrictions on hydraulic fracturing of wells, changes to the calculation of royalty payments, new safety requirements such as those involving rail transportation, and additional regulation of private energy commodity derivative and hedging activities. These and other potential laws, regulations and other requirements could increase our operating costs, reduce liquidity, delay operations or otherwise alter the way we conduct our business. This, in turn, could have a material adverse effect on our financial condition, results of operations and cash flows.

34



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 2016 budget proposal 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 exploration 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 in response to President Obama’s 2016 budget proposal or any other similar change in U.S. federal income tax law could eliminate or defer certain available tax deductions within the industry with respect to crude oil and natural gas exploration and development, and any such changes 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.
From time to time, we may use derivative instruments to manage commodity price risk. In 2010, the U.S. Congress adopted the Dodd-Frank Act, 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. This financial reform legislation includes provisions that require many derivative transactions previously executed over-the-counter to be executed through an exchange and be centrally cleared. In addition, this legislation calls for the imposition of position limits for swaps, including swaps involving physical commodities such as crude oil and natural gas, which have been proposed but have not been finalized. It also calls for the establishment of 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 revised capital requirements applicable to other market participants, such as swap dealers, may change the cost and availability 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 derivative activities to a separate entity, which may not be as credit-worthy as our current counterparty.
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 if enacted may require us to post collateral, which could adversely affect our available liquidity. If our use of derivatives becomes limited as a result of the 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, results of operations and cash flows.
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, results of operations and cash flows.

35



Energy conservation measures or initiatives that stimulate demand for alternative forms of energy could reduce the demand for the crude oil and natural gas we produce.
Fuel conservation measures, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices could reduce demand for the crude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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, 2014, non-operated properties represented 22% of our estimated proved developed reserves, 14% of our estimated proved undeveloped reserves, and 17% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures required to fund the development of such properties. Moreover, we are dependent on the other working interest owners on these projects to fund their contractual share of the capital expenditures. 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 could have a material adverse effect on our financial condition, results of operations and cash flows.
Our 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 goals.
Our credit facility contains restrictive covenants that limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, and merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (total debt less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity.
At December 31, 2014, our consolidated net debt to total capitalization ratio, as defined in the credit facility, was 0.55 to 1.00. Our total debt would need to independently increase by approximately $3.25 billion, or 54%, above existing levels at December 31, 2014 (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders' equity would need to independently decrease by approximately $1.75 billion, or 35%, below existing levels at December 31, 2014 to reach the maximum covenant ratio.
The indentures governing our senior notes contain covenants that, among others, limit our ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, and consolidate, merge or transfer certain assets.
The covenants in our credit facility and 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 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 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, could result in all amounts outstanding thereunder, together with accrued interest, to be due and payable. If our indebtedness is accelerated, our assets may not be sufficient to repay in full such 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 adversely affected by factors such as the availability, terms of and cost of capital, increases in interest rates, or a downgrade or other negative rating action with respect to our credit rating. 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 17, 2015, outstanding borrowings under our credit facility were $605 million and the impact of a 1% increase in interest rates on this amount of debt would result in

36



increased annual interest expense of approximately $6.1 million and a $3.8 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 financial condition and results of operations.
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 ($566 million in receivables at December 31, 2014); our joint interest receivables ($568 million at December 31, 2014); and counterparty credit risk associated with our derivative instrument receivables ($84 million at December 31, 2014). Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and 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 two largest purchasers of our crude oil and natural gas during the year ended December 31, 2014 accounted for a combined 25% of our total crude oil and natural gas revenues for the year. We generally do not require our counterparties to provide collateral to secure 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. 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, results of operations and cash flows.
Our derivative activities could result in financial losses or reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of crude oil and natural gas, from time to time we may enter into derivative instruments for a portion of our crude oil and/or natural gas production. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments for a summary of our crude oil and natural gas commodity derivative positions. We do 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 certain circumstances, including when:
production is less than the volume covered by the derivative instruments;
the counterparty 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 commodity prices. Our decision on the quantity and price at which we choose to hedge our future production, if any, 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 crude oil and natural gas reserves. We may choose not to hedge future production if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities in order to monetize favorable gain positions for the purpose of funding our capital program. In the fourth quarter of 2014, following a decrease in crude oil prices and related increase in the fair value of our derivative assets, substantially all of our outstanding crude oil derivative contracts were settled prior to the expiration of their contractual maturities, resulting in the receipt of cash proceeds totaling approximately $433 million. Consequently, our crude oil production and sales for 2015 and beyond are currently unhedged and directly exposed to continued volatility in crude oil market prices, whether favorable or unfavorable.
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, 2014, Harold G. Hamm, our Chairman and Chief Executive Officer, beneficially owned 252,956,381 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.

37



Mr. Hamm has controlled in the past, and may control in the future, companies engaged in the business 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 into, and may enter into, transactions from time to time with 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 but not limited to:
recoverable reserves;
future crude oil and natural gas prices and their differentials;
the quality of the title to acquired properties;
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, which we believe to be generally consistent with industry practices, of the subject properties. 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 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 sometimes 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 become the target of cyber attacks or 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, or that of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, including:
unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects; and
a cyber attack on a third party gathering, pipeline, or rail service provider could delay or prevent us from marketing our production, resulting in a loss of revenues.
These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability, which could have a material adverse effect on our financial condition, results of 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.

38



Item 1B.    Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2014.
 
Item 2.
Properties
The information required by Item 2 is contained in Part I, Item 1. Business—Crude Oil and Natural Gas Operations.

Item 3.
Legal Proceedings
In November 2010, an alleged class action was filed against the Company alleging the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The Company has responded to the petition, denied the allegations and raised a number of affirmative defenses. Discovery is ongoing and information and documents continue to be exchanged. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The class has not been certified. The class certification hearing is currently scheduled for May 25, 2015. Plaintiffs have indicated that if the class is certified they may seek damages in excess of $165 million which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes that the case meets the requirements for a class action and is vigorously defending the case.
The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows.

Item 4.
Mine Safety Disclosures
Not applicable.

39



Part II
 
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. Sales prices presented below have been retroactively adjusted, as applicable, to reflect our 2-for-1 stock split occurring in September 2014. No cash dividends were declared during the previous two years. 
 
 
2014
 
2013
 
 
Quarter Ended
 
Quarter Ended
 
 
March 31
 
June 30
 
September 30
 
December 31
 
March 31
 
June 30
 
September 30
 
December 31
High
 
$
63.23

 
$
79.44

 
$
80.91

 
$
67.25

 
$
47.00

 
$
44.82

 
$
54.10

 
$
60.89

Low
 
$
52.00

 
$
60.51

 
$
65.22

 
$
30.06

 
$
37.02

 
$
36.18

 
$
43.28

 
$
50.13

Cash Dividend
 

 

 

 

 

 

 

 

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. As of February 6, 2015, the number of record holders of our common stock was 745. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately 73,400. On February 17, 2015, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $48.67 per share.
The following table summarizes our purchases of our common stock during the quarter ended December 31, 2014:
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, 2014 to October 31, 2014
 

 

 

 

November 1, 2014 to November 30, 2014
 
166,120

(1)
$
53.97

(2)

 

December 1, 2014 to December 31, 2014
 



 

 

Total
 
166,120

 
$
53.97

 

 

 
(1)
In connection with restricted stock grants under the Company's 2005 Long-Term Incentive Plan ("2005 Plan") and 2013 Long-Term Incentive Plan ("2013 Plan"), we adopted a policy that enables employees to surrender shares to cover their tax liability. In May 2013, the 2013 Plan was adopted and replaced the Company's 2005 Plan. Restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. These 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 the restrictions lapsed on such shares.
(3)
We are unable to determine at this time the total amount of securities or approximate dollar value of securities that could potentially be surrendered to us pursuant to our policy that enables employees to surrender shares to cover their tax liability associated with the vesting of restrictions on shares.
Equity Compensation Plan Information
The following table sets forth the information as of December 31, 2014 relating to equity compensation plans:
 
 
 
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
 

 

 
18,104,686

Equity Compensation Plans Not Approved by Shareholders
 

 

 

 
(1)
Represents the maximum remaining shares available for issuance under the 2013 Plan.

40



Performance Graph
The following graph compares our common stock performance with the performance of the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Dow Jones US Oil and Gas Index (“Dow Jones US O&G Index”) for the period of December 2009 through December 2014. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, 2009 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.


41




Item 6.
Selected Financial Data
This section presents selected consolidated financial data for the years ended December 31, 2010 through 2014. The selected financial data presented below is not intended to replace our consolidated financial statements.
The following consolidated financial data has been derived from our audited consolidated financial statements for such periods. Shares and earnings per share amounts for 2010 through 2013 have been retroactively adjusted to reflect our 2-for-1 stock split occurring in September 2014. You should read the following selected financial data in connection with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and related notes included elsewhere in this report. The selected consolidated results are not necessarily indicative of results to be expected in future periods.
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
 
2011
 
2010
Income Statement data
 
 
 
 
 
 
 
 
 
 
In thousands, except per share data
 
 
Crude oil and natural gas sales (1)
 
$
4,203,022

 
$
3,573,431

 
$
2,349,500

 
$
1,633,718

 
$
942,989

Gain (loss) on derivative instruments, net (2)
 
559,759

 
(191,751
)
 
154,016

 
(30,049
)
 
(130,762
)
Total revenues (1)
 
4,801,618

 
3,421,807

 
2,542,587

 
1,636,088

 
833,530

Income from continuing operations
 
977,341

 
764,219

 
739,385

 
429,072

 
168,255

Net income
 
977,341

 
764,219

 
739,385