10-K 1 clr201310-k.htm FORM 10-K CLR 2013 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, 2013
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.  ¨
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, 2013 was approximately $4.9 billion, based upon the closing price of $86.06 per share as reported by the New York Stock Exchange on such date.
185,622,427 shares of our $0.01 par value common stock were outstanding on February 17, 2014.

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 2014, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Form 10-K.
 
 
 
 
 




Table of Contents 
 
 
 
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.
When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.




Glossary of Crude Oil and Natural Gas Terms
The terms defined in this section are used throughout this report:
“basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Bcf” One billion cubic feet of natural gas.
“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.
“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
“conventional play” An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.
“DD&A” Depreciation, depletion, amortization and accretion.
de-risked” Refers to acreage and locations in which the Company believes the geological risks and uncertainties related to recovery of crude oil and natural gas have been reduced as a result of drilling operations to date. However, only a portion of such acreage and locations have been assigned proved undeveloped reserves and ultimate recovery of hydrocarbons from such acreage and locations remains subject to all risks of recovery applicable to other acreage.
“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.
“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry gas” Refers to natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also may refer to gas that has been processed or treated to remove all natural gas liquids.
“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.
“ECO-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.
"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.
“HPAI” High pressure air injection.

i



“hydraulic fracturing” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production.
“in-field well” A well drilled between producing wells in a field to provide more efficient recovery of crude oil or natural gas from the reservoir.
“injection well” A well into which liquids or gases are injected in order to “push” additional crude oil or natural gas out of underground reservoirs and into the wellbores of producing wells. Typically considered an enhanced recovery process.
“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.
“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.
microseismic” or “microseismic monitoring Refers to the recording and imaging of seismic moments induced by hydraulic fracturing to provide technical data about fracture stimulation efficiency. This monitoring of fracture stimulations, being the industry's only measurement tool, yields technical data to allow for optimization of completion designs to help maximize production and/or reduce costs.
“net acres” or "net wells" Refers to the sum of the fractional working interests owned in gross acres or gross wells.
“NYMEX” The New York Mercantile Exchange.
“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 revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities and Exchange Commission (“SEC”). PV-10 is not a financial measure calculated in accordance with generally

ii



accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company’s crude oil and natural gas properties. The Company and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“resource play” Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and multi-stage fracturing technologies.
“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
“SCOOP” Refers to the South Central Oklahoma Oil Province, a term we use to describe an emerging area of crude oil and liquids-rich natural gas properties located in the Anadarko basin of south central Oklahoma.
“spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.
“standardized measure” Discounted future net cash flows estimated by applying the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December 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.
“3D (three dimensional seismic) defined locations” Locations that have been subjected to 3D seismic testing. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We do not typically evaluate reservoir productivity using 3D seismic technology.
“3D seismic” Seismic surveys using an instrument to send sound waves into the earth and collect data to help geophysicists define the underground configurations. 3D seismic provides three-dimensional pictures.
“unconventional play” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.
“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“waterflood” The injection of water into a crude oil reservoir to “push” additional crude oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.
“wellbore” The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called a well or borehole.
“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

iii



Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, included in this report are forward-looking statements. When used in this report, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes the expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors included in this report, quarterly reports, registration statements filed from time to time with the SEC, and other announcements we make from time to time.
Without limiting the generality of the foregoing, certain statements incorporated by reference, if any, or included in this report constitute forward-looking statements.
Forward-looking statements may include statements about:
our business strategy;
our future operations;
our crude oil and natural gas reserves;
our technology;
our financial strategy;
crude oil, natural gas liquids, and natural gas prices and differentials;
the timing and amount of future production of crude oil and natural gas and flaring activities;
the amount, nature and timing of capital expenditures;
estimated revenues, expenses and results of operations;
drilling and completing of wells;
competition;
marketing of crude oil and natural gas;
transportation of crude oil, natural gas liquids, and natural gas to markets;
exploitation or property acquisitions and dispositions;
costs of exploiting and developing our properties and conducting other operations;
our financial position;
general economic conditions;
credit markets;
our liquidity and access to capital;
the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;
our future operating results;
plans, objectives, expectations and intentions contained in this report that are not historical, including, without limitation, statements regarding our future growth plans;
our commodity or other hedging arrangements; and
the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.
We caution you these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling, completion and production equipment and services and transportation infrastructure, environmental risks, drilling and

iv



other operating risks, lack of availability and security of computer-based systems, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part I, Item 1A. Risk Factors in this report, quarterly reports, registration statements filed from time to time with the SEC, and other announcements we make from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this report.

v



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,” “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.
We were originally formed in 1967 to explore for, develop and produce crude oil and natural gas properties. Through 1989, our activities and growth remained focused primarily in Oklahoma. In 1989, we expanded our activity into the North region. Our operations are now geographically concentrated in the North region, with that region comprising approximately 77% of our crude oil and natural gas production and approximately 86% of our crude oil and natural gas revenues for the year ended December 31, 2013. Approximately 76% of our estimated proved reserves as of December 31, 2013 are located in the North region.
We have focused our operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2013, crude oil accounted for approximately 71% of our total production and approximately 87% of our crude oil and natural gas revenues. Crude oil represents approximately 68% of our estimated proved reserves as of December 31, 2013.
We focus our exploration activities in large new or developing crude oil and liquids-rich natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture 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, adding 1,046 MMBoe of proved crude oil and natural gas reserves through extensions and discoveries from January 1, 2009 through December 31, 2013 compared to 85 MMBoe added through proved reserve acquisitions during that same period. In October 2012, we announced a five-year growth plan to triple our production and proved reserves from year-end 2012 to year-end 2017.
As of December 31, 2013, our estimated proved reserves were 1,084.1 MMBoe, with estimated proved developed reserves of 406.8 MMBoe, or 38% of our total estimated proved reserves. For the year ended December 31, 2013, we generated crude oil and natural gas revenues of $3.6 billion and operating cash flows of $2.6 billion. For the year ended December 31, 2013, daily production averaged 135,919 Boe per day, a 39% increase over average production of 97,583 Boe per day for the year ended December 31, 2012. Average daily production for the quarter ended December 31, 2013 increased 35% to 144,254 Boe per day from 106,831 Boe per day for the quarter ended December 31, 2012.
The table below summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2013, average daily production for the quarter ended December 31, 2013 and the reserve-to-production index in our principal regions. The PV-10 values shown below are not intended to represent the fair market value of our crude oil and natural gas properties. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. See “Critical Accounting Policies and Estimates” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report for further discussion of uncertainties inherent to the reserve estimates. 
Our reserve estimates as of December 31, 2013 are based primarily on a reserve report prepared by our independent reserve engineers, Ryder Scott Company, L.P (“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 94% of our proved natural gas reserves as of December 31, 2013. Our internal technical staff evaluated the remaining properties. Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2013 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2013 through December 2013, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were

1



$96.78 per Bbl for crude oil and $3.67 per MMBtu for natural gas ($91.50 per Bbl for crude oil and $5.36 per Mcf for natural gas adjusted for location and quality differentials).
 
 
December 31, 2013
 
Average daily
production for
fourth quarter
2013
(Boe per day)
 
 
 
Annualized
reserve/production
index (2)
 
 
Proved
reserves
(MBoe)
 
Percent
of total
 
PV-10 (1)
(In millions)
 
Net
producing
wells
 
Percent
of total
 
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
688,741

 
63.5
%
 
$
13,093

 
779

 
80,374

 
55.7
%
 
23.5

Montana Bakken
 
52,401

 
4.8
%
 
1,437

 
233

 
12,961

 
9.0
%
 
11.1

Red River units
 
 
 
 
 
 
 


 
 
 
 
 
 
Cedar Hills
 
54,191

 
5.0
%
 
1,522

 
130

 
10,498

 
7.3
%
 
14.1

Other Red River units
 
22,419

 
2.1
%
 
427

 
131

 
3,900

 
2.7
%
 
15.7

Other
 
1,884

 
0.2
%
 
32

 
16

 
812

 
0.6
%
 
6.4

South Region:
 
 
 
 
 
 
 

 
 
 
 
 
 
SCOOP
 
214,667

 
19.8
%
 
3,286

 
74

 
23,754

 
16.5
%
 
24.8

Northwest Cana
 
29,827

 
2.8
%
 
198

 
73

 
6,696

 
4.6
%
 
12.2

Arkoma Woodford
 
11,103

 
1.0
%
 
69

 
59

 
2,769

 
1.9
%
 
11.0

Other
 
8,892

 
0.8
%
 
111

 
277

 
2,490

 
1.7
%
 
9.8

Total
 
1,084,125

 
100.0
%
 
$
20,175

 
1,772

 
144,254

 
100.0
%
 
20.6

 
(1)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $3.9 billion. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities.
(2)
The Annualized Reserve/Production Index is the number of years that estimated proved reserves would last assuming current production continued at the same rate. This index is calculated by dividing annualized fourth quarter 2013 production into estimated proved reserve volumes at December 31, 2013.

2



The following table provides additional information regarding our key development areas as of December 31, 2013 and the budgeted amounts we plan to spend on exploratory and development drilling, capital workovers, and facilities in 2014. 
 
 
 
 
 
 
 
 
 
 
2014 Plan
 
 
Developed acres
 
Undeveloped acres
 
Gross wells
planned for
drilling
 
Capital
expenditures (1)
(in millions)
 
 
Gross
 
Net
 
Gross
 
Net
 
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
900,678

 
530,682

 
504,898

 
378,370

 
802

 
$
2,233

Montana Bakken
 
159,943

 
135,426

 
214,358

 
165,343

 
68

 
413

Red River units
 
156,703

 
137,294

 

 

 
16

 
50

Niobrara - Colorado/Wyoming
 
12,087

 
8,529

 
126,662

 
69,526

 

 

Other
 
22,194

 
7,220

 
235,931

 
179,265

 
6

 
40

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
74,019

 
48,990

 
603,665

 
354,864

 
159

 
876

Northwest Cana
 
120,668

 
73,777

 
110,120

 
71,314

 

 
13

Arkoma Woodford
 
110,973

 
26,359

 
4,568

 
434

 

 

Other
 
100,710

 
46,008

 
197,434

 
167,506

 
9

 
65

East Region
 

 

 
152,762

 
144,363

 

 

Total
 
1,657,975

 
1,014,285

 
2,150,398

 
1,530,985

 
1,060

 
$
3,690


(1)
The capital expenditures budgeted for 2014 as reflected above include amounts for drilling, capital workovers and facilities and exclude budgeted amounts for land of $300 million, seismic of $30 million, and $30 million for vehicles, computers and other equipment. Potential acquisition expenditures are not budgeted.
Our Business Strategy
Our goal is to increase shareholder value by finding and developing crude oil and natural gas reserves at costs that provide an attractive rate of return on our investment. The principal elements of our business strategy are:
Focus on crude oil. During the late 1980s we began to believe the valuation potential for crude oil exceeded that of natural gas. Accordingly, we began to shift our reserve and production profiles toward crude oil. As of December 31, 2013, crude oil comprised 68% of our total proved reserves and 71% of our 2013 annual production.
Growth Through Drilling. A substantial portion of our annual capital expenditures are invested in drilling projects and acreage acquisitions. From January 1, 2009 through December 31, 2013, proved crude oil and natural gas reserve additions through extensions and discoveries were 1,046 MMBoe compared to 85 MMBoe of proved reserve acquisitions.
Internally Generated Prospects. Although we periodically evaluate and complete strategic acquisitions, our technical staff has internally generated a substantial portion of the opportunities for the investment of our capital. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than later entrants into a developing play.
Focus on Unconventional Crude Oil and Natural Gas Resource Plays. Our experience with three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture 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, Bakken, and Oklahoma Woodford formations. The Oklahoma Woodford is a widespread unconventional shale reservoir that produces in various basins across the state of Oklahoma, with our properties being primarily concentrated in the SCOOP, Northwest Cana and Arkoma areas of the play. Production rates in the Red River units also have been sustained through the use of enhanced recovery technologies including water and high pressure air injection. Our production from the Red River units, the Bakken field, and the Oklahoma Woodford comprised approximately 48,324 MBoe, or 97%, of our total crude oil and natural gas production for the year ended December 31, 2013.
Acquire Significant Acreage Positions in New or Developing Plays. In addition to the 970,325 net undeveloped acres held in the Bakken play in North Dakota and Montana and the Oklahoma Woodford, we held 560,660 net undeveloped acres in other crude oil and natural gas plays as of December 31, 2013. Our technical staff is focused on identifying and testing new

3



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:
Large Acreage Inventory. We held 1,530,985 net undeveloped acres and 1,014,285 net developed acres as of December 31, 2013. Approximately 68% of the net undeveloped acres are located within unconventional resource plays in the Bakken (North Dakota and Montana), Woodford (Oklahoma) and the Niobrara (Colorado and Wyoming). The remaining balance of the net undeveloped acreage is located in conventional plays including 3D-defined locations for the Lodgepole (North Dakota), Morrow-Springer (Western Oklahoma) and Frio (South Texas) plays.
Experience with Horizontal Drilling and Enhanced Recovery Methods. We have substantial experience with horizontal drilling and enhanced recovery methods. In 1992, we drilled our first horizontal well, and we have drilled over 2,100 horizontal wells since that time. We continue to be a leader in the development of new drilling and completion technologies. Our trademarked ECO-Pad drilling concept, which allows for drilling multiple wells from a single pad, is becoming a standard drilling approach in the industry because it improves land use and increases operating efficiencies. We have drilled as many as 14 wells on a pad site and have the opportunity to increase this number in the future based on surface availability, technology and well spacing. We are also a leader in extending lateral drilling lengths, in some instances up to three miles. In 2012, we completed the first multiple-unit spaced well drilled in Oklahoma, which had a horizontal section that was twice the length of previous laterals in the area. Longer laterals are believed to have a positive impact on well productivity and economics. Additionally, we are a leader in the exploration and evaluation of the lower layers or “benches” of the Three Forks formation in the Bakken field (referred to as the "Lower Three Forks"), initially targeting the first bench of the Three Forks in mid-2008 followed by the successful completion of our first well in the second bench in October 2011. In 2012, we successfully completed the first well ever drilled in the third bench of the Three Forks. In 2013, we completed our first of four pilot density projects in the Bakken and Three Forks formations, which included our first wells drilled in the fourth bench. The density project demonstrated the productive potential of multiple stacked zones and is helping us determine the optimum drilling and spacing pattern for future development of these reservoirs.
Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2013, we operated properties comprising 87% of our total proved reserves and 86% of our PV-10. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and fracture stimulation methods used.
Experienced Management Team. Our senior management team has extensive expertise in the crude oil and natural gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the crude oil and natural gas industry in 1967. Our 9 senior officers have an average of 30 years of crude oil and natural gas industry experience.
Strong Financial Position. In the second half of 2013, our corporate credit rating was upgraded to 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 most recently the SCOOP play. Our growth has been matched with a disciplined capital sourcing approach which has enabled a strong credit profile. We have a credit facility with lender commitments totaling $1.5 billion which may be increased up to $2.5 billion to provide additional liquidity if needed to maintain our growth strategy, take advantage of business opportunities, and fund our capital program. We had $1.2 billion of available borrowing capacity under our credit facility at December 31, 2013 after considering outstanding borrowings and letters of credit. We believe our planned exploration and development activities will be funded substantially from our operating cash flows and credit facility borrowings. Our 2014 capital expenditures budget has been established based on our current expectation of available cash flows from operations and availability under our credit facility. Should expected available cash flows from operations materially differ from expectations, we believe our credit facility has sufficient availability to fund any deficit or that we can reduce our capital expenditures to be in line with cash flows from operations.

4



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, our independent reserve engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole and production data, seismic data and well test data.
The following tables set forth our estimated proved crude oil and natural gas reserves and PV-10 by reserve category as of December 31, 2013. The total Standardized Measure of discounted cash flows as of December 31, 2013 is also presented. Ryder Scott evaluated properties representing approximately 99% of our PV-10, 99% of our proved crude oil reserves, and 94% of our proved natural gas reserves as of December 31, 2013, and our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K.  
 
 
Crude Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
 
PV-10 (1)
(in millions)
Proved developed producing
 
277,845

 
761,729

 
404,800

 
$
10,461.0

Proved developed non-producing
 
785

 
7,240

 
1,992

 
49.6

Proved undeveloped
 
459,158

 
1,309,051

 
677,333

 
9,664.8

Total proved reserves
 
737,788

 
2,078,020

 
1,084,125

 
$
20,175.4

Standardized Measure (1)
 
 
 
 
 
 
 
$
16,295.8

 
(1)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $3.9 billion. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities.

5



The following table provides additional information regarding our proved crude oil and natural gas reserves by region as of December 31, 2013. 
 
 
Proved Developed
 
Proved Undeveloped
 
 
Crude Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
 
Crude Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
159,372

 
260,318

 
202,759

 
401,841

 
504,846

 
485,982

Montana Bakken
 
31,727

 
32,169

 
37,088

 
12,771

 
15,252

 
15,313

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
51,263

 
7,039

 
52,436

 
1,755

 

 
1,755

Other Red River units
 
17,472

 
13,400

 
19,705

 
2,714

 

 
2,714

Other
 
619

 
7,590

 
1,884

 

 

 

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
14,607

 
238,629

 
54,379

 
39,096

 
727,150

 
160,288

Northwest Cana
 
1,433

 
102,676

 
18,546

 
981

 
61,803

 
11,281

Arkoma Woodford
 
18

 
66,509

 
11,103

 

 

 

Other
 
2,119

 
40,639

 
8,892

 

 

 

Total
 
278,630

 
768,969

 
406,792

 
459,158

 
1,309,051

 
677,333

The following table provides information regarding changes in total proved reserves for the periods presented.  
 
 
Year Ended December 31,
MBoe
 
2013
 
2012
 
2011
Proved reserves at beginning of year
 
784,677

 
508,438

 
364,712

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

 
2,237

Extensions, discoveries and other additions
 
444,654

 
233,652

 
161,981

Production
 
(49,610
)
 
(35,716
)
 
(22,581
)
Sales of minerals in place
 

 
(7,838
)
 

Purchases of minerals in place
 
458

 
81,992

 
2,089

Proved reserves at end of year
 
1,084,125

 
784,677

 
508,438

Revisions of previous estimates. Revisions represent changes in previous reserve estimates, upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions for the year ended December 31, 2013 primarily represent the removal of proved undeveloped ("PUD") reserves resulting from a decision in 2013 to allocate a greater focus of our 5-year growth plan to our drilling programs in higher rates-of-return crude oil and liquids-rich natural gas areas of the Bakken and SCOOP while continuing to build on the early success in our development of the Lower Three Forks reservoirs in the Bakken. Another contributing factor is our increased focus on multi-well pad drilling in the Bakken, which resulted in the removal of PUDs in certain areas in favor of PUDs more likely to be developed with pad drilling where operating efficiencies may be realized to maximize rates of return. These factors contributed to the removal of 81 MMBoe of PUD reserves in 2013.
Extensions, discoveries and other additions. These are additions to our proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling activity and strong production growth in the Bakken field. Proved reserve additions in the Bakken totaled 276 MMBoe for the year ended December 31, 2013. Additionally, 2013 extensions and discoveries were significantly impacted by successful drilling results in the emerging SCOOP play, resulting in 158 MMBoe of proved reserve additions during the year. Significant progress continued to be made in 2013 in developing and expanding our Bakken and SCOOP assets, both laterally and vertically, through strategic exploration, development, planning and technology. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2013 drilling

6



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. During the year ended December 31, 2012, we disposed of certain non-strategic properties in Oklahoma, Wyoming, and our East region in an effort to redeploy capital to our strategic areas that we believe will deliver higher future growth potential. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions for further discussion of our 2012 dispositions. We 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 the year ended December 31, 2012 primarily reflect the Company’s acquisitions of properties in the Bakken play of North Dakota. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Property Acquisitions and Dispositions and Note 14. Property Transaction with Related Party for further discussion of our 2012 acquisitions. We may continue to participate as a buyer of properties when and if we have the ability to increase our position in strategic plays at competitive terms.
Proved Undeveloped Reserves
Our PUD reserves at December 31, 2013 totaled 677,333 MBoe, consisting of 459,158 MBbls of crude oil and 1,309,051 MMcf of natural gas. PUD reserves at December 31, 2013 were concentrated in the Bakken and SCOOP plays, our most active development areas, with those districts comprising 74% and 24%, respectively, of our total PUD reserves at year-end 2013. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2013.
 
 
Crude Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
Proved undeveloped reserves at December 31, 2012
 
334,293

 
795,585

 
466,891

Revisions of previous estimates
 
(52,440
)
 
(251,475
)
 
(94,354
)
Extensions and discoveries
 
240,653

 
981,118

 
404,173

Purchases of minerals in place
 
23

 
26

 
28

Conversion to proved developed reserves
 
(63,371
)
 
(216,203
)
 
(99,405
)
Proved undeveloped reserves at December 31, 2013
 
459,158

 
1,309,051

 
677,333

Revisions of previous estimates. During the year ended December 31, 2013, we removed 315 gross (174 net) PUD locations, which resulted in the removal of 42 MMBo and 235 Bcf (81 MMBoe) of PUD reserves. These removals were due to the aforementioned decision to allocate a greater focus of our 5-year growth plan to drilling programs in higher rates-of-return areas of the Bakken, SCOOP, and Lower Three Forks, with increased focus on areas capable of being developed via multi-well pad drilling. These factors contributed to the removal of PUD reserves in certain areas having less attractive rates of return or are otherwise less likely to be developed via pad drilling.
Extensions and discoveries. Extensions and discoveries were primarily due to increases in PUD reserves associated with our successful drilling activity in the Bakken and SCOOP. PUD reserve additions in the Bakken totaled 205 MMBo and 258 Bcf (248 MMBoe) in 2013, while SCOOP PUD reserve additions totaled 33 MMBo and 687 Bcf (147 MMBoe). See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2013 drilling activities in the Bakken and SCOOP plays.
Conversion to proved developed reserves. In 2013, we developed approximately 21% of our PUD reserves and 20% of our PUD locations booked as of December 31, 2012 through the drilling of 360 gross (208 net) development wells at an aggregate capital cost of approximately $1.7 billion.
Development plans. We have acquired substantial leasehold positions in the Bakken field and SCOOP play. Our drilling programs to date in those areas have focused on proving our undeveloped leasehold acreage through strategic exploratory drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease. While we will continue to drill strategic exploratory wells and build on our current leasehold position, we expect to continue increasing our focus on developing our PUD locations. Development of our existing PUD reserves at December 31, 2013 is expected to occur within five years of the date of initial booking of the PUDs. Estimated future development costs relating to the development of PUD reserves are projected to be approximately $2.5 billion in 2014, $2.2 billion in 2015, $2.3 billion in 2016, $2.0 billion in 2017, and $1.0 billion in 2018. We expect our cash flows from operations and our credit facility

7



will be sufficient to fund these future development costs. We had no PUD reserves at December 31, 2013 that remained undeveloped beyond five years from the date of initial booking.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process.
Ryder Scott, our independent 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 94% of our proved natural gas reserves as of December 31, 2013 included in this Annual Report on Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Annual Report on Form 10-K for further discussion of the qualifications of Ryder Scott personnel.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. In the fourth quarter, our technical team 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 reserves 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 quarterly 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 29 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. The reserve estimates are reviewed and approved by the President and Chief Operating Officer and certain other members of senior management.
Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2013: 
 
 
Developed acres
 
Undeveloped acres
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
900,678

 
530,682

 
504,898

 
378,370

 
1,405,576

 
909,052

Montana Bakken
 
159,943

 
135,426

 
214,358

 
165,343

 
374,301

 
300,769

Red River units
 
156,703

 
137,294

 

 

 
156,703

 
137,294

Niobrara - Colorado/Wyoming
 
12,087

 
8,529

 
126,662

 
69,526

 
138,749

 
78,055

Other
 
22,194

 
7,220

 
235,931

 
179,265

 
258,125

 
186,485

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
74,019

 
48,990

 
603,665

 
354,864

 
677,684

 
403,854

Northwest Cana
 
120,668

 
73,777

 
110,120

 
71,314

 
230,788

 
145,091

Arkoma Woodford
 
110,973

 
26,359

 
4,568

 
434

 
115,541

 
26,793

Other
 
100,710

 
46,008

 
197,434

 
167,506

 
298,144

 
213,514

East Region
 

 

 
152,762

 
144,363

 
152,762

 
144,363

Total
 
1,657,975

 
1,014,285

 
2,150,398

 
1,530,985

 
3,808,373

 
2,545,270



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The following table sets forth the number of gross and net undeveloped acres as of December 31, 2013 that are expected to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates or the leases are renewed. 
 
 
2014
 
2015
 
2016
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
126,232

 
84,679

 
143,555

 
118,609

 
107,462

 
107,257

Montana Bakken
 
63,762

 
51,399

 
65,541

 
46,973

 
38,375

 
36,632

Red River units
 
2,716

 
1,377

 
7,967

 
5,423

 
12,054

 
12,042

Niobrara - Colorado/Wyoming
 
13,574

 
8,800

 
83,531

 
45,692

 
23,538

 
10,816

Other
 
3,063

 
1,873

 
10,991

 
4,101

 
1,440

 
588

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
122,067

 
71,061

 
105,279

 
58,198

 
151,040

 
81,042

Northwest Cana
 
34,804

 
21,997

 
27,686

 
15,668

 
33,024

 
26,521

Arkoma Woodford
 
1,040

 
120

 

 

 

 

Other
 
1,202

 
733

 
85,919

 
64,276

 
15,932

 
16,767

East Region
 
9,657

 
7,486

 
14,187

 
9,760

 
5,128

 
4,695

Total
 
378,117

 
249,525

 
544,656

 
368,700

 
387,993

 
296,360

Drilling Activity
During the three years ended December 31, 2013, we drilled exploratory and development wells as set forth in the table below:
 
 
 
2013
 
2012
 
2011
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
75

 
51.5

 
76

 
37.0

 
50

 
23.4

Natural gas
 
40

 
23.7

 
78

 
43.8

 
109

 
45.9

Dry holes
 
3

 
2.1

 
1

 
1.0

 
2

 
1.3

Total exploratory wells
 
118

 
77.3

 
155

 
81.8

 
161

 
70.6

Development wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
734

 
250.9

 
561

 
211.3

 
380

 
126.1

Natural gas
 
26

 
5.4

 
5

 
2.4

 
17

 
1.6

Dry holes
 

 

 
3

 
1.1

 
5

 
0.6

Total development wells
 
760

 
256.3

 
569

 
214.8

 
402

 
128.3

Total wells
 
878

 
333.6

 
724

 
296.6

 
563

 
198.9

As of December 31, 2013, there were 404 gross (160.8 net) wells in the process of drilling, completing or waiting on completion.
As of February 17, 2014, we operated 43 rigs on our properties. Our rig activity during 2014 will depend on potential drilling efficiency gains and crude oil and natural gas prices and, accordingly, our rig count may increase or decrease from current levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost. See Part I, Item 1A. Risk Factors—The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.

9



Summary of Crude Oil and Natural Gas Properties and Projects
Throughout the following discussion, we discuss our budgeted number of wells and capital expenditures for 2014. Although we cannot provide any assurance, we believe our cash flows from operations, remaining cash balance, and our credit facility, including our ability to increase our borrowing capacity thereunder, will be sufficient to satisfy our 2014 capital budget. We may choose to access the capital markets for additional financing to take advantage of business opportunities that may arise if such financing can be arranged at favorable terms. The actual amount and timing of our capital expenditures may differ materially from our estimates as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments. Further, a decline in commodity prices could cause us to curtail our actual capital expenditures. Conversely, an increase in commodity prices could result in increased capital expenditures.
As referred to throughout this report, a “play” is a term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves. “Conventional plays” are areas believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps. “Unconventional plays” are areas believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but generally require horizontal drilling, fracture stimulation treatments or other special recovery processes to achieve economic production. Unconventional plays tend to have low permeability and may be closely associated with source rock as is the case with oil and gas shale, tight oil and gas sands and coalbed methane. Our operations in unconventional plays include operations in the Bakken and Woodford plays and the Red River units. Our operations within conventional plays include operations in the Lodgepole of North Dakota, Morrow-Springer of western Oklahoma and Frio in south Texas. In general, unconventional plays require the application of more advanced technology and higher drilling and completion costs to produce relative to conventional plays. These technologies can include hydraulic fracturing treatments, horizontal wellbores, multilateral wellbores, or some other technique or combination of techniques to expose more of the reservoir to the wellbore.
References throughout this report to “3D seismic” refer to seismic surveys of areas by means of an instrument which records the travel time of vibrations sent through the earth and the interpretation thereof. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are better able to define the underground configurations. “3D defined locations” are those locations that have been subjected to 3D seismic testing. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We do not typically evaluate reservoir productivity using 3D seismic technology.
North Region
Our properties in the North region represented 82% of our PV-10 as of December 31, 2013 and 75% of our average daily Boe production for the three months ended December 31, 2013. For the three months ended December 31, 2013, our average daily production from such properties was 108,545 Boe per day, an increase of 30% over our average daily production for the three months ended December 31, 2012. 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. Total production from the Bakken field reached a record 1.1 million barrels of oil equivalent ("MMBoe") per day in October 2013, up 39% over October 2012 based on data published by IHS Inc. and the North Dakota Industrial Commission. North Dakota remains the second largest oil producing state in the U.S. due to production growth in the Bakken field. As of December 31, 2013, there were 183 rigs actively drilling in the Bakken field.
We continue to be a leading producer, leasehold owner and driller in the Bakken field. Our Bakken field production averaged 93,335 Boe per day during the three months ended December 31, 2013, up 38% from our average daily Bakken field production for the three months ended December 31, 2012. Our properties within the Bakken field represented 72% of our PV-10 as of December 31, 2013 and 65% of our average daily Boe production for the three months ended December 31, 2013. Our total proved Bakken field reserves as of December 31, 2013 were 741 MMBoe, up 32% over our proved Bakken field reserves as of December 31, 2012. As of December 31, 2013, we controlled the largest leasehold position in the Bakken field with 1,779,877 gross (1,209,821 net) acres. Approximately 55% of our net acreage was developed and the remaining 45% was undeveloped as of December 31, 2013. As of December 31, 2013, we were the most active driller in the Bakken field, with 20 active operated rigs. As of December 31, 2013, we had completed 2,636 gross (1,025 net) wells in the Bakken field. Our

10



inventory of proved undeveloped drilling locations in the Bakken field as of December 31, 2013 totaled 1,964 gross (1,119 net) wells.
We made significant progress with our development and exploration drilling programs in the Bakken field during 2013, completing a total of 749 gross (267 net) wells. We have reduced our drilling and completion costs on operated North Dakota Bakken wells from approximately $9.2 million in 2012 to approximately $8.0 million in 2013. The largest contributors to these cost reductions are multi-well pad development which reduced the overall footprint of our operations, advancements in stimulation and drilling technology, rig moving and location construction. We exited the year with over 70% of our rig activity on multi-well pads.
Of particular note was the success of our exploration program in the lower layers or “benches” of the Three Forks formation which demonstrated that wells completed in the Lower Three Forks reservoirs may be productive over an area at least 3,800 square miles in size, adding potential incremental recoverable reserves to the Bakken field. We also had success expanding the field extents onto our undeveloped leasehold through our step-out drilling program and we completed the first of four pilot density projects initiated during the year. These pilot density projects are designed to help us determine the optimum drilling and spacing pattern for future development of the Bakken and Three Forks reservoirs. We also initiated a pilot secondary recovery project to evaluate the potential for increasing the ultimate recovery of crude oil from the Bakken field through secondary injection methods. Progress of these pilot projects is ongoing.
We plan to invest approximately $2.5 billion drilling 870 gross (287 net) wells in the Bakken field during 2014, of which approximately 84% is expected to be invested in North Dakota and the remaining 16% in Montana. We plan to exit 2014 with 23 rigs drilling in the Bakken field with 19 rigs located in North Dakota and 4 rigs in Montana.
North Dakota Bakken
Our production and reserve growth in the Bakken field during 2013 came primarily from our activities in North Dakota. Production increased to an average rate of 80,374 Boe per day during the three months ended December 31, 2013, up 36% over the 2012 fourth quarter. Proved reserves increased 33% year-over-year to 689 MMBoe as of December 31, 2013. Our North Dakota Bakken properties represented 65% of our PV-10 at December 31, 2013 and 56% of our average daily Boe production for the three months ended December 31, 2013. In 2013, we completed 678 gross (211 net) wells, bringing our total number of wells drilled in North Dakota Bakken to 2,267 gross (788 net) wells as of December 31, 2013. As of December 31, 2013, we had 1,405,576 gross (909,052 net) acres in the North Dakota Bakken field, of which 58% of the net acreage is developed and the remaining 42% is undeveloped. Our inventory of proved undeveloped locations stood at 1,904 gross (1,074 net) wells as of December 31, 2013.
Our 2013 drilling activity in North Dakota focused on (1) developing our derisked areas, (2) expanding the field vertically and horizontally through step-out exploration drilling and (3) pilot density drilling to determine optimum well spacing and pattern for full field development. We successfully achieved our 2013 objectives in each of these areas and expect to continue making progress with these initiatives in 2014.
Our exploration drilling in North Dakota focused primarily on evaluating the productivity of the Lower Three Forks "benches" which include the Three Forks 2 ("TF2"), Three Forks 3 ("TF3"), and the Three Forks 4 ("TF4") reservoirs. These benches are layers of dolomite reservoir rock that underlie the proven producing Upper Three Forks bench known as the Three Forks 1 ("TF1"). Core work we completed over a year ago showed that these Lower Three Forks benches contained crude oil but it was unknown if they would produce crude oil at economic rates. During 2013, we successfully conducted a 24 well exploration drilling program to test these Lower Three Forks benches and completed 13 gross (9.5 net) wells in the TF2, 9 gross (7.2 net) wells in the TF3 and 2 gross (1.6 net) wells in the TF4. Results demonstrated that wells completed in the TF2 and TF3 are capable of producing crude oil at rates comparable to the TF1 across an area over 3,800 square miles in size. This discovery is significant as these results suggest the TF2 and TF3 reservoirs may add incremental recoverable reserves to the Bakken field. Results from the TF4 wells are being evaluated to determine their productive capabilities. At December 31, 2013, we have recorded approximately 20 MMBoe of proved reserves associated with the TF2 and TF3 benches in North Dakota Bakken.
To further assess the incremental reserve potential of the Lower Three Forks reservoirs and determine the optimum drilling density and pattern to maximize crude oil recovery from the Bakken field, we initiated four pilot density drilling projects during 2013. A total of 44 wells were drilled in these four projects during 2013. The first of the four pilot density projects to be completed and put into production was our Hawkinson unit. It was the first 1,280-acre unit that was fully developed on 320-acre spacing in the Bakken field and included four Middle Bakken wells, three TF1 wells, four TF2 wells and three TF3 wells. These 14 wells produced at a maximum combined initial 24 hour production rate of 14,850 barrels of oil equivalent per day. The Hawkinson density pilot employed several state of the art technologies including the largest downhole microseismic monitoring survey ever conducted in the world. All of this was done to help us determine the best inter-well spacing and pattern for future development of the Bakken field. We are currently monitoring production from the Hawkinson unit and

11



incorporating the microseismic and technical data to assess performance. We also completed drilling operations on three additional pilot density projects in 2013 - the Tangsrud, Rollefstad, and Wahpeton projects - which we expect to begin producing during the first half of 2014. The Tangsrud and Rollefstad projects, like the Hawkinson project, are developing the Middle Bakken and first three benches of the Three Forks on 320-acre spacing while the Wahpeton project is developing the same zones on 160-acre spacing.
In 2014, we plan to invest approximately $2.1 billion drilling 802 gross (240 net) wells in the North Dakota Bakken. Approximately 13% of the capital expenditures will be spent on exploratory drilling which will include additional step-out drilling and three new pilot density projects. These new pilot density projects will further test the development of the Middle Bakken and first three benches of the Three Forks on 160-acre spacing. The remainder of the capital is expected to be spent drilling development wells in the field including our full field development program in the Antelope prospect in McKenzie and Williams Counties of North Dakota. This development drilling will be done using ECO-Pad technology. As of December 31, 2013, we had 16 operated rigs drilling in the North Dakota Bakken and plan to exit 2014 at 19 rigs.
Montana Bakken
Our Montana Bakken properties are located primarily within the Elm Coulee field in Richland County, Montana. Production from our Montana Bakken properties reached an all time high during the three months ended December 31, 2013, averaging 12,961 Boe per day over that period, up 52% from the average daily rate for the three months ended December 31, 2012. This reflects the success of our ongoing drilling program to optimize and expand our Montana Bakken properties. During 2013, we completed 71 gross (56 net) wells in Montana bringing our total number of wells drilled in Montana Bakken to 369 gross (237 net) wells as of December 31, 2013. As of December 31, 2013 our Montana Bakken properties represented 7% of our PV-10 and 9% of our average daily Boe production for the three months ended December 31, 2013. As of December 31, 2013, we had 374,301 gross (300,769 net) acres in Montana Bakken, of which 45% of the net acreage is developed and the remaining 55% is undeveloped. As of December 31, 2013, we had 60 gross (45 net) proved undeveloped locations identified in the Montana Bakken field.
In 2014, we plan to invest approximately $412 million drilling 68 gross (47 net) wells in the Montana Bakken. Our drilling will focus on additional infill development of Elm Coulee and continued expansion of the Elm Coulee field onto our undeveloped acreage north of the field. As of December 31, 2013, we had 4 rigs operating in the Montana Bakken and plan to exit 2014 with the same number of rigs.
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, a thin continuous, dolomite formation at depths of 8,000 to 9,500 feet. Our principal producing properties in the Red River units include the Cedar Hills units in North Dakota and Montana, the Medicine Pole Hills units in North Dakota, and the Buffalo Red River units in South Dakota. Our properties in the Red River units comprise a portion of the Cedar Hills field, which was listed by the U.S. Energy Information Administration in 2010 as the 9th largest onshore field in the lower 48 states of the United States ranked by 2009 proved liquid reserves.
All combined, our Red River units and adjacent areas represented 10% of our PV-10 as of December 31, 2013 and 10% of our average daily Boe production for the three months ended December 31, 2013. Our average daily production from these legacy properties decreased 2% in the fourth quarter of 2013 compared to the 2012 fourth quarter. The relatively shallow decline in these mature properties is due to optimization efforts and some limited drilling activity. Proved reserves were 77 MMBoe as of December 31, 2013. We are continuing to extend the performance life of our properties in the Red River units primarily by improving our water and air injection efficiency and taking other measures to optimize production. Additional enhanced recovery via carbon dioxide injection is currently being studied. As of December 31, 2013, we had 156,703 gross (137,294 net) acres in the Red River units and adjacent areas, all of which is developed acreage.
We have allocated $39 million of our 2014 capital expenditure budget to the Red River units and adjacent areas to support one drilling rig. Additional capital will be used to support injection projects and continued investment in facilities and infrastructure.
North Region Marketing Activities
Crude Oil. We continue to build upon a portfolio approach (rail and pipe) to marketing our crude oil that began in 2008 with our first shipments of crude oil by rail out of the Williston Basin. During 2013, we continued our efforts to shift Bakken crude oil sales to coastal markets in the United States with less dependence on currently available pipeline markets. Rail transportation costs are typically higher than pipeline transportation costs per barrel mile, but market prices realized in U.S. coastal markets continue to be competitive with currently available pipeline markets. We plan to continue pursuing this

12



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 fashion through the coming years, especially as we accelerate development drilling using ECO-Pad technology.
Natural Gas. Field infrastructure build-out continued in the Williston Basin in 2013 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 2013, we continued to make notable progress in adhering to our flaring reduction initiatives. For the year ended December 31, 2013, the percentage of our operated natural gas production flared in North Dakota Bakken was less than 11%, compared to 15% in 2012 and 19% in 2011. We expect to further reduce this amount as we continue to build out infrastructure and transition to a greater use of ECO-Pad development in 2014 and beyond.
South Region
Our properties in the South region represented 18% of our PV-10 as of December 31, 2013 and 25% of our average daily Boe production for the three months ended December 31, 2013. For the three months ended December 31, 2013, our average daily production from such properties was 35,709 Boe per day, up 58% from the same period in 2012. Our principal producing properties in this region are located in the emerging SCOOP play in south-central Oklahoma.
SCOOP
Our SCOOP properties are located in southern Oklahoma primarily in Garvin, Grady, Stephens, Carter, McClain and Love Counties. SCOOP represented 16% of our PV-10 as of December 31, 2013 and 17% of our average daily Boe production for the three months ended December 31, 2013. For the year ended December 31, 2013, SCOOP production grew 318% over 2012 due to our increased drilling activity in the play. For the three months ended December 31, 2013, SCOOP production averaged 23,754 Boe per day, up 233% over our average daily production for the three months ended December 31, 2012. As of December 31, 2013, we held 677,684 gross (403,854 net) acres under lease in SCOOP, of which 12% of the net acreage was developed and the remaining 88% of the net acreage was undeveloped. Our inventory of proved undeveloped drilling locations in SCOOP as of December 31, 2013 totaled 309 gross (153 net) wells.
We completed 77 gross (42 net) wells in SCOOP during 2013 and as of December 31, 2013 we had completed a total of 145 gross (79 net) wells in SCOOP. Our 2013 drilling program included exploration, step-out and development wells focused on de-risking the play and holding our acreage by production. The year 2013 was a particularly impactful year for SCOOP as our drilling results and results from others in the industry established both a crude oil and condensate rich, natural gas producing fairway that combined is approximately 20 miles wide and 120 miles long. Based on our 2013 drilling results, SCOOP is proving to be another significant asset for the Company with considerable potential for production and reserve growth.
A possible upside to SCOOP is the potential to encounter additional pay from a variety of conventional and potential unconventional reservoirs overlying and underlying the Woodford formation. There are over 60 different conventional reservoirs known to produce in the SCOOP area. These conventional reservoirs have the potential to produce locally under our SCOOP acreage.
In 2014, we plan to invest approximately $865 million to drill 159 gross (72 net) wells in the SCOOP play. Approximately 40% of these wells will be multi-unit wells. Multi-unit wells enable us to drill two spacing units from one location, which reduces well costs and our overall surface footprint. The 2014 drilling program will continue to focus on expanding the known productive extents of SCOOP and de-risking our acreage. It will also include pilot density projects to determine the optimum well spacing and pattern for full scale development of SCOOP in the future. We also expect to invest approximately $19 million to acquire approximately 230 square miles of additional proprietary 3D seismic data to guide future drilling. As of December 31, 2013, we had 18 operated rigs drilling in the SCOOP play.
South Region Marketing Activities
Crude Oil. Due to the proximity of our South region operations to the market center in Cushing, Oklahoma, we typically sell our South region production directly to midstream trading and transportation companies at the wellhead with price realizations that correlate with WTI benchmark pricing. We anticipate continuing this approach through early 2015 and to begin delivery of production from our SCOOP properties via wellhead pipeline gathering and intrastate pipeline systems directly into Cushing as field infrastructure is constructed and developed.

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Natural Gas. In 2013, field infrastructure build-out continued at a rapid pace in the Anadarko Basin and in SCOOP as third party midstream gathering and processing companies expanded field gathering and compression facilities, cryogenic processing capacity and NGL pipeline capacity to market centers. Throughout our South region leasehold, we are coordinating our well completion operations to coincide with well connections to gathering systems in order to minimize greenhouse gas emissions.
Production and Price History
The following table sets forth summary information concerning our production results, average sales prices and production costs for the years ended December 31, 2013, 2012 and 2011 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2013: 
 
 
Year ended December 31,
 
 
2013
 
2012
 
2011
Net production volumes:
 
 
 
 
 
 
Crude oil (MBbls) (1)
 
 
 
 
 
 
North Dakota Bakken
 
23,513

 
15,936

 
8,480

SCOOP
 
2,004

 
478

 
96

Total Company
 
34,989

 
25,070

 
16,469

Natural gas (MMcf)
 
 
 
 
 
 
North Dakota Bakken
 
26,783

 
16,454

 
7,523

SCOOP
 
29,438

 
7,060

 
1,927

Total Company
 
87,730

 
63,875

 
36,671

Crude oil equivalents (MBoe)
 
 
 
 
 
 
North Dakota Bakken
 
27,977

 
18,679

 
9,733

SCOOP
 
6,910

 
1,654

 
417

Total Company
 
49,610

 
35,716

 
22,581

Average sales prices: (2)
 
 
 
 
 
 
Crude oil ($/Bbl)
 
 
 
 
 
 
North Dakota Bakken
 
$
89.45

 
$
84.50

 
$
88.43

SCOOP
 
95.63

 
89.37

 
93.02

Total Company
 
89.93

 
84.59

 
88.51

Natural gas ($/Mcf)
 
 
 
 
 
 
North Dakota Bakken
 
$
6.26

 
$
5.55

 
$
7.18

SCOOP
 
5.59

 
4.01

 
7.56

Total Company
 
5.25

 
4.20

 
5.24

Crude oil equivalents ($/Boe)
 
 
 
 
 
 
North Dakota Bakken
 
$
81.17

 
$
76.95

 
$
82.56

SCOOP
 
51.55

 
34.01

 
56.30

Total Company
 
72.71

 
66.83

 
73.05

Average costs per Boe: (2)
 
 
 
 
 
 
Production expenses ($/Boe)
 
 
 
 
 
 
North Dakota Bakken
 
$
5.50

 
$
4.31

 
$
4.05

SCOOP
 
0.99

 
1.02

 
1.30

Total Company
 
5.69

 
5.49

 
6.13

Production taxes and other expenses ($/Boe)
 
$
6.69

 
$
6.42

 
$
6.42

General and administrative expenses ($/Boe) (3)
 
$
2.91

 
$
3.42

 
$
3.23

DD&A expense ($/Boe)
 
$
19.47

 
$
19.44

 
$
17.33

 
(1)
Crude oil sales volumes differ from production volumes because, at various times, we have stored crude oil in inventory due to pipeline line fill requirements, low commodity prices, or transportation constraints or we have sold crude oil from inventory. Crude oil sales volumes were 4 MBbls less than production volumes for the year ended December 31, 2013,

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112 MBbls less than production volumes for the year ended December 31, 2012 and 30 MBbls less than production volumes for the year ended December 31, 2011.
(2)
Average sales prices and per unit costs have been calculated using sales volumes and exclude any effect of derivative transactions.
(3)
General and administrative expense ($/Boe) includes non-cash equity compensation expenses of $0.80 per Boe, $0.82 per Boe, and $0.73 per Boe for the years ended December 31, 2013, 2012 and 2011, respectively, and corporate relocation expenses of $0.04 per Boe, $0.22 per Boe and $0.14 per Boe for the years ended December 31, 2013, 2012, and 2011, respectively.
The following table sets forth information regarding our average daily production by region during the fourth quarter of 2013: 
 
 
Fourth Quarter 2013 Daily Production
 
 
Crude Oil
(Bbls per day)
 
Natural Gas
(Mcf per day)
 
Total
(Boe per day)
North Region:
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
North Dakota Bakken
 
67,164

 
79,263

 
80,374

Montana Bakken
 
11,422

 
9,237

 
12,961

Red River units
 
 
 
 
 
 
Cedar Hills
 
10,101

 
2,382

 
10,498

Other Red River units
 
3,468

 
2,592

 
3,900

Other
 
367

 
2,672

 
812

South Region:
 
 
 
 
 
 
SCOOP
 
6,567

 
103,121

 
23,754

Northwest Cana
 
542

 
36,920

 
6,696

Arkoma Woodford
 
4

 
16,594

 
2,769

Other
 
808

 
10,085

 
2,490

Total
 
100,443

 
262,866

 
144,254

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, 2013: 
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total Wells
 
 
Gross    
 
Net    
 
Gross    
 
Net    
 
Gross    
 
Net    
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
2,261

 
778

 
6

 
1

 
2,267

 
779

Montana Bakken
 
361

 
232

 
2

 
1

 
363

 
233

Red River units
 


 


 


 


 


 


Cedar Hills
 
136

 
130

 

 

 
136

 
130

Other Red River units
 
145

 
131

 

 

 
145

 
131

Other
 
33

 
15

 
4

 
1

 
37

 
16

South Region:
 
 
 
 
 
 
 
 
 
 
 

SCOOP
 
45

 
23

 
96

 
51

 
141

 
74

Northwest Cana
 
11

 
6

 
157

 
67

 
168

 
73

Arkoma Woodford
 
3

 

 
397

 
59

 
400

 
59

Other
 
208

 
162

 
232

 
115

 
440

 
277

Total
 
3,203

 
1,477

 
894

 
295

 
4,097

 
1,772

As of December 31, 2013, we did not own interests in any wells containing multiple completions.

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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 any property, we procure a title opinion from external legal counsel and perform curative work necessary to satisfy requirements pertaining to material title defects. We generally will not commence drilling operations on a property until we have cured material title defects 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.
As a result of pipeline constraints, the continuous increase in Williston Basin production, and our desire to transport our crude oil to U.S. coastal markets which provide favorable pricing, in December 2013 we transported approximately 70% of our operated crude oil production from our North region by rail. We are using both manifest and unit train facilities for these shipments and anticipate these shipments will continue.
We have a strategic mix of gas transport, processing and sales arrangements for our natural gas production. Our natural gas production is sold at various points along the market chain from wellhead to points downstream under monthly interruptible packaged-volume deals, short-term seasonal packages, and long-term multi-year acreage dedication type contracts. All of our natural gas is sold at market. Some of our contracts allow us the flexibility to sell at the well or, with notice, take our gas “in-kind”, transport, process, and sell in the market area. Midstream natural gas gathering and processing companies are our primary transporters and purchasers.
Our marketing of crude oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, 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 years ended December 31, 2013, 2012 and 2011, sales to Marathon Crude Oil Company accounted for approximately 12%, 21% and 41% of our total crude oil and natural gas revenues, respectively. Sales to United Energy Trading accounted for approximately 11% of our total crude oil and natural gas revenues for both of the years ended December 31, 2013 and 2012. Additionally, sales to Tesoro Refining and Marketing Company accounted for approximately 15% of our total crude oil and natural gas revenues for the year ended December 31, 2013. No other purchasers accounted for more than 10% of our total crude oil and natural gas revenues for 2013, 2012 and 2011. We believe the loss of our largest purchaser would not have a material adverse effect on our operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in our producing regions.
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

16



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.
Regulation of the Crude Oil and Natural Gas Industry
All of our operations are conducted onshore in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and interpretations affecting our industry have been pervasive and are continuously reviewed by legislators and regulators, including the imposition of new or increased requirements on us and other industry participants. Applicable laws and regulations and other requirements affecting our industry and its members often carry substantial penalties for failure to comply. Such requirements may have a significant effect on the exploration, development, production and sale of crude oil and natural gas. These requirements increase the cost of doing business and, consequently, affect profitability. We believe we are in substantial compliance with all laws and regulations and policies currently applicable to our operations and our continued compliance with existing requirements will not have a material adverse impact on us. However, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws and regulations may be amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. We do not expect any future legislative or regulatory initiatives will affect our operations in a manner materially different than they would affect our similarly situated competitors.
Following is a discussion of significant laws and regulations that may affect us in the areas in which we operate.
Regulation of sales 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 does regulate the exportation of petroleum and petroleum products, and these regulations could restrict the markets for these commodities and thus affect sales prices. With regard to our physical sales of crude oil and derivative instruments relating to crude oil, we are required to comply with anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”). See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—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 our operations in a way that materially differs from the effect on the operations of our competitors who are similarly situated.
Further, interstate pipelines and intrastate common carrier pipelines must provide service on an equitable basis. Under this standard, such pipelines must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When such pipelines operate at full capacity, access is governed by prorating provisions, which may be set forth in the pipelines’ published tariffs. We believe we generally will have access to crude oil pipeline transportation services to the same extent as our similarly situated competitors.
A portion of our North region crude oil production is shipped to market centers using rail transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s (“U.S. DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relating to crude-by-rail transportation. In addition, third party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the U.S. DOT, the Federal Railroad Administration (“FRA”) of the DOT, OSHA, as well as other federal regulatory agencies. Additionally, various state and local

17



agencies have jurisdiction over disposal of hazardous waste and seek to regulate movement of hazardous materials in ways not preempted by federal law.

In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of 2008, which implemented regulations governing different areas related to railroad safety. Recently, in response to train derailments occurring in the United States and Canada in 2013, U.S. regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the National Transportation Safety Board (“NTSB”) issued a series of recommendations to the FRA and PHMSA to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) to develop an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity of product carried on a train, and (iii) to audit shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the U.S. Department of Transportation issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of petroleum crude oil be handled as a Packing Group I or II hazardous material.

We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows. At this time, it is not possible to estimate the potential impact on our business if new federal or state rail transportation regulations are enacted.
Regulation of 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 that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. 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 other natural gas producers.
With regard to our physical sales of natural gas and derivative instruments relating to natural gas, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and the CFTC. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—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.”

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Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policies on gathering systems have varied in the past, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, 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 our operations, but the natural gas industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes, 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 our operations in a way that materially differs from the effect on the operations of 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. The effect of these regulations is to limit the amount of crude oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production, severance or excise tax with respect to the production and sale of crude oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the crude oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Other federal 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. This financial reform legislation includes provisions that require many derivative transactions that were then executed over-the-counter to be executed through an exchange and be centrally cleared. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules and regulations to implement the new legislation. The CFTC has issued final regulations to implement significant aspects of the legislation, including new rules for the registration of swap dealers and major swap participants (and related definitions of those terms), definitions of the term “swap,” rules to establish the ability to rely on the commercial end-user exception from the central clearing and exchange trading requirements, requirements for reporting and record keeping, rules on customer protection in the context of cleared swaps, and position limits for swaps and other transactions based on the price of certain reference contracts, some of which are referenced in our swap contracts. The position limits regulation has been vacated by a Federal court; however, the CFTC has proposed replacement rules. Key regulations that have not yet been finalized include those establishing margin requirements for uncleared swaps and regulatory capital requirements for swap dealers.
In December 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants. Mandatory clearing is now required for all such market participants, unless an exception is available, and certain interest rate swaps became subject to the trade execution requirements on February 15, 2014. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps, and the trade execution requirement does not apply to swaps that are not subject to a clearing mandate. Although we expect to qualify for the end-user exception from the clearing requirement for our swaps, mandatory clearing requirements and revised capital requirements applicable to other market participants, such as swap dealers, along with changes to the markets for swaps as a result of the trade execution requirement, may change the cost and availability of the swaps we use for hedging.

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The CFTC’s swap regulations may require or cause our counterparties to collect margin from us, and if any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract market or swap execution facility. The ultimate effect of the proposed new rules and any additional regulations on our business is uncertain. Of particular concern is whether our status as a commercial end-user will allow our derivative counterparties to not require us to post margin in connection with our commodity price risk management activities. The remaining final rules and regulations on major provisions of the legislation, such as new margin requirements, will be established through regulatory rule making.
In addition to the CFTC’s swap regulations, other jurisdictions, including Canada, the European Union, Switzerland, Hong Kong, Singapore, Japan and Australia, are in the process of adopting or implementing laws and regulations relating to transactions in derivatives, including margin and central clearing requirements, which in each case may affect our counterparties and the derivatives markets generally. Other rules, including the restrictions on proprietary trading adopted under Section 619 of the Dodd-Frank Act, also known as the Volcker Rule, may alter the business practices of our counterparties and in some cases may cause them to stop transacting in or making markets in derivatives. Moreover, federal banking regulators are reevaluating the authorization under which banking entities subject to their authority may engage in physical commodities transactions.
Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area, to the extent applicable to us or our derivative counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial and commercial risks related to fluctuations in commodity prices. 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 planned to adopt the Dodd-Frank Act requirement that registrants disclose certain payments made to the U.S. Federal government and foreign governments in connection with the commercial development of crude oil, natural gas or minerals. The disclosure requirements were challenged by certain business groups and were subsequently vacated by a Federal court in July 2013. The SEC did not appeal the ruling and plans to issue a revised proposal, the timing of which is uncertain.
The SEC has adopted the Dodd-Frank Act requirement that registrants disclose the use of conflict minerals in their products, and whether any of those minerals originated in certain conflict-ridden regions of Africa and financed or benefited armed groups. Certain business groups challenged the disclosure requirements; however, the requirements were upheld by a Federal court in a July 2013 ruling. The ruling has been appealed by the plaintiffs involved in the matter. We monitor our operations to determine if any disclosure or reporting obligations arise under the conflict mineral rules.
Energy Policy Act of 2005. The Energy Policy Act of 2005 (“EPAct 2005”) included a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and made 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. The anti-market manipulation rules and enhanced civil penalty authority reflect an expansion of the FERC’s enforcement authority.
FERC Market Transparency and Reporting Rules. The FERC requires wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers, and natural gas producers, to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. The FERC also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. Failure to comply with these reporting requirements could subject us to enhanced civil penalty liability provided under EPAct 2005.

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FTC and CFTC Market Manipulation Rules. Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the FTC. Under the EISA, the FTC issued its Petroleum Market Manipulation Rule (the “Rule”), which became effective November 4, 2009, and prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. The Rule also bans intentional failures to state a material fact when the omission makes a statement misleading and distorts, or is likely to distort, market conditions for any product covered by the Rule. The FTC holds substantial enforcement authority under the EISA, including authority to request that a court impose fines of up to $1,000,000 per day per violation. Under the Commodity Exchange Act, the CFTC is directed to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act, the CFTC has adopted anti-market manipulation regulations that prohibit, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to assess fines of up to the greater of $1,000,000 or triple the monetary gain for violations of its anti-market manipulation regulations. 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 of these or the above regulatory changes to our crude oil and natural gas operations. We do not believe we will be affected by any such action materially different than similarly situated competitors.
Environmental, health and safety regulation
General. Our operations are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:
require the acquisition of various permits before drilling commences;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with crude oil and natural gas drilling, production and transportation activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals; and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
These laws and regulations may also restrict the rate of crude oil and natural gas production below a rate 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. Continental is committed to conducting its operations in a manner that protects the health, safety and welfare of the public, its employees and the environment. We strive to operate in accordance with all applicable regulatory requirements and have focused on continuously improving our health, safety, security and environmental (“HSS&E”) performance. We believe excellent HSS&E performance is critical to the long-term success of our business, and is a key component in maximizing return to shareholders. We also believe achieving this excellence requires the commitment and involvement of all employees in the Company, and we expect the same level of commitment from our contractors and vendors. Our commitment to HSS&E excellence is a paramount objective.
In connection with our HSS&E initiatives, we actively work to identify and manage the environmental risks and impact of our operations. Further, we set corporate objectives aimed at producing continuous improvement of our HSS&E efforts and we seek to provide the leadership and resources to enable our workforce to achieve our objectives. We routinely monitor our HSS&E performance to assess our conformity with environmental protection initiatives.
We take a proactive and disciplined approach to emergency preparedness and business continuity planning to address the health, safety, security, and environmental risks inherent to our industry. We continually train our workforce and conduct drills to improve awareness and readiness to mitigate such risks. Further, emergency response plans are maintained that establish procedures to be utilized during any type of emergency affecting our personnel, facilities or the environment.
One current focus of our HSS&E initiatives is the reduction of air emissions produced from our operations, particularly with respect to flaring of natural gas from our operated well sites in the Bakken field of North Dakota, our most active area. The rapid growth of crude oil production in North Dakota in recent years, coupled with a lack of established natural gas

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transportation infrastructure in the state, has led to an industry-wide increase in flaring of natural gas produced in association with crude oil production. We recognize the environmental and financial risks associated with natural gas flaring and manage these risks on an ongoing basis. We set internal flaring reduction targets and to date have taken numerous actions to reduce flaring from our operated well sites. Our ultimate goal is to reduce natural gas flaring from our operated well sites to as close to zero percent flaring as possible. In operating areas such as the Buffalo Red River units in South Dakota, the quality of the natural gas is not adequate to meet requirements for sale, so we employ processes to efficiently combust the gas and minimize impacts to the environment.
In 2013, we continued to make notable progress in adhering to our flaring reduction initiatives. The percentage of our operated natural gas production flared in North Dakota Bakken, our most active area, was less than 11% in 2013, compared to 15% in 2012 and 19% in 2011. We believe this reduction is a notable accomplishment given the significant increase in our natural gas production in the Bakken field, including areas with less developed infrastructure. Flaring from our operated well sites in North Dakota Bakken is significantly less than our industry peers operating in the play. According to data published by the North Dakota Industrial Commission ("NDIC"), our industry as a whole was flaring approximately 30% of produced natural gas volumes in the state as of late 2013. Since we are one of the largest producers in the North Dakota Bakken field, we believe the percentage of natural gas flared by the industry as a whole would be higher than 30% if Continental’s results were excluded from the NDIC’s data. Continental is a participant in the NDIC’s Flaring Reduction Task Force and is actively engaged in working with other task force members and the NDIC to develop action plans for mitigating natural gas flaring in the state.
We are experiencing similar or better flaring results in our other key operating areas outside of North Dakota. In Montana Bakken, we flared approximately 9% of the natural gas produced from our operated well sites in 2013. Additionally, flared natural gas volumes from our operated SCOOP and Northwest Cana properties in Oklahoma are negligible given the existence of established natural gas transportation infrastructure in that state.
Through our HSS&E initiatives, we will continue to work toward maintaining an industry-leading position with respect to flaring reduction efforts in North Dakota and our other key operating areas. We expect to further reduce flared natural gas volumes as we continue to build out transportation infrastructure and transition to a greater use of pad drilling in 2014 and beyond. Our flaring reduction progress is and will be dependent upon external factors such as investment from third parties in the development of gas gathering systems, state regulations, and the granting of reasonable right-of-way access by land owners, among other factors.
We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Although we believe our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not materially impact our financial position or results of operations.
Environmental, health and safety laws and regulations. Some of the existing environmental, health and safety laws and regulations we are subject to include, among others: (i) regulations by the Environmental Protection Agency (“EPA”) and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act and analogous state laws that may require the removal of previously disposed wastes (including wastes disposed of or released by prior owners or operators), the cleanup of property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) federal 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 federal Occupational Safety and Health Act ("OSHA") and comparable state statutes, which require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations, and (xi) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material.
Climate change. Federal, state and local laws and regulations are increasingly being enacted to address concerns about the effects the emission of carbon dioxide and other identified “greenhouse gases” may have on the environment and climate

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worldwide. These effects are widely referred to as “climate change.” Since its December 2009 endangerment finding regarding the emission of carbon dioxide, methane and other greenhouse gases, the EPA has begun regulating sources of greenhouse gas emissions under the federal Clean Air Act. Among several regulations requiring reporting or permitting for greenhouse gas sources, the EPA finalized its “tailoring rule” in May 2010 that identifies which stationary sources of greenhouse gases are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology for, their greenhouse gases. In November 2010, the EPA also finalized its greenhouse gas reporting requirements for certain oil and gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule requires annual reporting to the EPA of greenhouse gas emissions by such regulated facilities.
In April 2012, the EPA issued final rules that established new air emission controls for crude oil and natural gas production and natural gas processing operations. These rules were published in the Federal Register on August 16, 2012. The EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with crude oil and natural gas production and processing activities. The final rules require the use of reduced emission completions or “green completions” on all hydraulically-fractured wells completed or refractured after January 1, 2015 in order to achieve a 95% reduction in the emission of VOCs. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules may require modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Moreover, in recent years the U.S. Congress has considered establishing a cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. Under past proposals, the EPA would issue or sell a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of such legislation, if adopted, would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products, and natural gas. In addition, while the prospect for such cap-and-trade legislation by the U.S. Congress remains uncertain, several states have adopted, or are in the process of adopting, similar cap-and-trade programs.
As a crude oil and natural gas company, the debate on climate change is relevant to our operations because the equipment we use to explore for, develop and produce crude oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the crude oil and natural gas we sell, emits carbon dioxide and other greenhouse gases. Thus, any current or future federal, state or local climate change initiatives could adversely affect demand for the crude oil and natural gas we produce by stimulating demand for alternative forms of energy that do not rely on the combustion of fossil fuels, and therefore could have a material adverse effect on our business. Although our compliance with any greenhouse gas regulations may result in increased compliance and operating costs, we do not expect the compliance costs for currently applicable regulations to be material. Moreover, while it is not possible at this time to estimate the compliance costs or operational impacts for any new legislative or regulatory developments in this area, we do not anticipate being impacted to any greater degree than other similarly situated competitors.
Hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formations to stimulate crude oil and natural gas production. Some activists have attempted to link hydraulic fracturing to various environmental problems, including adverse effects to drinking water supplies and migration of methane and other hydrocarbons. As a result, several federal agencies are studying the environmental risks with respect to hydraulic fracturing or evaluating whether to restrict its use. From time to time, legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities from the definition of “underground injection,” thereby requiring the crude oil and natural gas industry to obtain permits for hydraulic fracturing and to require disclosure of the additives used in the process. If adopted, such legislation could establish an additional level of regulation and permitting at the federal level.
Scrutiny of hydraulic fracturing activities continues in other ways. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing environmental issues associated with hydraulic fracturing. The EPA has commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the draft results of which are anticipated to be available in 2014. Further, on May 11, 2012, the Bureau of Land Management (“BLM”) issued a proposed rule 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. BLM published a supplemental notice of proposed rulemaking on May 24, 2013, which replaced the proposed rulemaking issued by the agency in May 2012. Additionally, on February 11, 2014 the EPA issued guidance governing the use of diesel fuel in hydraulic fracturing fluids. The guidance

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identifies five different variations of diesel and outlines new permitting guidelines for their use, along with technical recommendations for meeting the standards. In addition to these federal initiatives, several state and local governments, including states in which we operate, have moved to require disclosure of fracturing fluid components or otherwise to regulate their use more closely. In certain areas of the United States, new drilling permits for hydraulic 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, the hydraulic fracturing process could make it more difficult and more expensive to complete crude oil and natural gas wells in low-permeability formations, increase our costs of compliance and doing business, and delay, prevent or prohibit the development of natural resources from unconventional formations. Compliance, or the consequences of 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.
Employees
As of December 31, 2013, we employed 929 people. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. We utilize the services of independent contractors to perform various field and other services.
Company Contact Information
Our corporate internet website 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 Ethics, please see our website. We intend to disclose amendments to, or waivers from, our Code of Ethics by posting to our website. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.
We intend to use our website as a means of disclosing material information and for complying with our disclosure obligations under SEC Regulation FD. Such disclosures will be included on our website in the “For Investors” section. Accordingly, investors should monitor that portion of our website in addition to following our press releases, SEC filings and public conference calls and webcasts.
We file periodic reports and proxy statements with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website 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.
 
Item 1A.
Risk Factors
You should carefully consider each of the risks described below, together with all other information contained in this report, before deciding to invest in shares of our common stock. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline and you may lose all or part of your investment.
We are subject to certain risks and hazards due to the nature of 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.

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A substantial or extended decline in crude oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure needs and financial commitments.
The price we receive for our crude oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
worldwide and regional economic conditions impacting the global supply and demand for crude oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries;
the price and quantity of imports of foreign crude oil and natural gas;
political conditions in or affecting other crude oil-producing and natural gas-producing countries;
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulations;
the level of national and global crude oil and natural gas exploration and production;
the level of national and global crude oil and natural gas inventories;
localized supply and demand 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 level and effect of trading in commodity futures markets;
weather conditions;
technological advances affecting energy consumption; and
the price and availability of alternative fuels or other energy sources.
Lower crude oil and natural gas prices could reduce our cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; limit our ability to borrow money or raise additional capital; and reduce the amount of crude oil and natural gas we can economically produce.
Substantial, extended decreases in crude oil and natural gas prices would render uneconomic a significant portion of our exploration, development and exploitation projects. This may result in significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in crude oil or natural gas prices would materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
A substantial portion of our producing properties are located in the North region, making us vulnerable to risks associated with having operations concentrated in this geographic area.
Our operations are geographically concentrated in the North region, with that region comprising approximately 77% of our crude oil and natural gas production and approximately 86% of our crude oil and natural gas revenues for the year ended December 31, 2013. Additionally, as of December 31, 2013 approximately 76% of our estimated proved reserves were located in the North region.
Because of this geographic concentration, the success and profitability of our operations may be disproportionately exposed to the effect of regional events. These include, among others, fluctuations in the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor and infrastructure capacity. In addition, our operations in the North region may be adversely affected by seasonal weather and lease stipulations designed to protect wildlife, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in the North region also increases exposure to unexpected events that may occur in this region such as natural disasters, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations and cash flows.

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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. Economic turmoil or uncertainty could reduce demand for crude oil and natural gas and put downward pressure on the prices of crude oil and natural gas. This would negatively impact our revenues, margins, profitability, operating cash flows, liquidity and financial condition. Such weakness or uncertainty could also cause our commodity hedging arrangements to become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. Furthermore, our ability to collect receivables may be adversely impacted.
Historically, we have used cash flows from operations, borrowings under our credit facility and capital market transactions to fund capital expenditures. Volatility in U.S. and global financial and equity markets, including market disruptions, limited liquidity, and interest rate volatility, may increase our cost of financing. We have a credit facility with lender commitments totaling $1.5 billion. In the future, we may not be able to access adequate funding under our credit facility as a result of (i) a decrease in our credit ratings that triggers the reinstatement of a borrowing base requirement, subjecting us to the risk that other events may adversely impact the size of our borrowing base following reinstatement, (ii) a decline in commodity prices, or (iii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations or increase their commitments as required under the credit facility. Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required and on terms we find acceptable. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our financial condition and results of operations.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on acceptable terms, which could lead to a decline in our crude oil and natural gas reserves and production.
The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. In 2013, we invested approximately $3.84 billion in our capital program, inclusive of property acquisitions. In October 2012, we announced a five-year growth plan to triple our production and proved reserves from year-end 2012 to year-end 2017. Our capital expenditures for 2014 are budgeted to be $4.05 billion, excluding acquisitions which are not budgeted, with $3.69 billion allocated for drilling, capital workovers and facilities. To date, our capital expenditures have been financed with cash generated by operations, borrowings under our credit facility and the issuance of debt and equity securities. The actual amount and timing of future capital expenditures may differ materially from our estimates as a result of, among others, commodity prices, available cash flows, unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments. Improvement in commodity prices may result in an increase in actual capital expenditures. Conversely, a significant decline in commodity prices could result in a decrease in actual capital expenditures. We intend to finance future capital expenditures primarily through cash flows from operations and borrowings under our credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional debt requires a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital needs, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
Our cash flows from operations and access to capital are subject to a number of variables, including but not limited to:
the amount of our proved reserves;
the volume of crude oil and natural gas we are able to produce and sell from existing wells;
the prices at which crude oil and natural gas are sold;
our ability to acquire, locate and produce new reserves; and
the ability and willingness of our banks to extend credit or the financial markets to accept offerings of our senior notes.
If revenues or our ability to borrow decrease as a result of lower crude oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by

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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 and results of operations and our ability to achieve our growth plan.
Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.
Risks we face while drilling include, but are not limited to, failing to place our well bore in the desired target producing zone; not staying in the desired drilling zone while drilling horizontally through the formation; failing to run our casing the entire length of the well bore; and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages; failing to run tools the entire length of the well bore during completion operations; and not successfully cleaning out the well bore after completion of the final fracture stimulation stage.
Further, many factors may curtail, delay or cancel scheduled drilling projects, including:
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 hydraulic fracturing processes such as water and proppants;
mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or train derailments;
adverse weather conditions and natural disasters, such as flooding, blizzards and ice storms;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
reductions in crude oil and natural gas prices;
limited availability of financing with acceptable terms;
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 third party service providers or us;
limitations in infrastructure, including transportation capacity, or the market for crude oil and natural gas; and
delays imposed by or resulting from compliance with regulatory requirements including permitting.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company's current estimates of reserves could change, potentially in material amounts, in the future.
The process of estimating crude oil and natural gas reserves is complex 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, 2013.
In order to prepare reserves estimates, we must project production rates and the amount and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and

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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.
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.
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 cost and timing of development and production expenditures;
the amount and timing of actual production;
the actual prices we receive for sales of crude oil and natural gas; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry in general.
Actual future prices and costs may materially differ from those used in our estimate of the present value of future net revenues. If crude oil prices decline by $10.00 per barrel, our PV-10 as of December 31, 2013 would decrease approximately $2.8 billion. If natural gas prices decline by $1.00 per Mcf, our PV-10 as of December 31, 2013 would decrease approximately $1.3 billion.
Our use of enhanced recovery methods creates uncertainties that could adversely affect our results of operations and financial condition.
One of our business strategies is to economically develop unconventional crude oil and natural gas resource plays using enhanced recovery technologies. For example, we may inject water and high-pressure air into formations on some of our properties to increase the production of crude oil and natural gas. The additional production and reserves attributable to the use of these enhanced recovery methods are inherently difficult to predict. If enhanced recovery programs do not allow for the extraction of crude oil and natural gas in the manner or to the extent we anticipate, our future results of operations and financial condition could be materially adversely affected.
If crude oil and natural gas prices decrease, we may be required to write down the carrying values of our crude oil and natural gas properties.
Accounting rules require that we periodically review the carrying values of our crude oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying values of our crude oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

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Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our cash flows and results of operations.
Unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services, including key components used in hydraulic fracturing processes such as water and proppants, could delay or cause us to incur significant expenditures not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
We may incur substantial losses and be subject to substantial liability claims as a result of our crude oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and 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;
natural disasters; and
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by third party service providers or us.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
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 generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Prospects we decide to drill may not yield crude oil or natural gas in economically producible quantities.
Prospects we decide to drill that do not yield crude oil or natural gas in economically producible quantities may adversely affect our results of operations and financial condition. In this report, we describe some of our current prospects and plans to explore

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those prospects. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. It is not possible to predict with certainty in advance of drilling and testing whether any particular prospect will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or be economically producible. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in economically producible quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals, available transportation capacity, and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. 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 60% of our total net undeveloped acreage at December 31, 2013. At that date, we had leases representing 249,525 net acres expiring in 2014, 368,700 net acres expiring in 2015, and 296,360 net acres expiring in 2016. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Our business depends on crude oil and natural gas transportation facilities, most of which are owned by third parties, and on the availability of rail transportation
The marketability of our crude oil and natural gas production depends in part on the availability, proximity and capacity of pipeline and rail systems owned by third parties. The lack or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of crude oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and rail systems, labor disputes and general economic conditions could adversely affect our ability to produce, gather, transport and sell crude oil and natural gas. We presently transport a significant portion of operated crude oil production from our North region to market centers by rail, with approximately 70% of such production being shipped by rail in December 2013.
The disruption of third-party pipelines or rail transportation facilities due to labor disputes, maintenance, civil disturbances, public protests, terrorist attacks, cyber attacks, adverse weather, regulatory developments, equipment failures or accidents, including pipeline ruptures or train derailments, could negatively impact our ability to market and deliver our products and achieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such pipeline or rail facilities 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. See the subsequent risk factor titled Proposed legislation and regulation under consideration could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business for a discussion of regulations being introduced that could potentially impact the transportation of crude oil by rail.
Our business depends on the availability of water. Limitations or restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
With current technology, water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal could limit our ability to use techniques such as hydraulic fracturing. This could have a material adverse effect on our ability to economically find and develop crude oil and natural gas reserves.

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We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in developed and producing areas. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our crude oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations, including those governing environmental protection, health and safety, and the discharge of materials into the environment. In order to conduct operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. 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.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders 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 and results of operations could be adversely affected. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a description of the laws and regulations that affect us.
Climate change legislation or regulations governing the emissions of “greenhouse gases” could result in increased operating costs and reduce demand for the crude oil, natural gas and natural gas liquids we produce.
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climate changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of several regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act, such as the so-called “tailoring rule” adopted in May 2010, which imposes permitting and best available control technology requirements on the largest greenhouse gas stationary sources. In November 2010, the EPA also finalized its greenhouse gas reporting requirements for certain oil and gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule requires annual reporting to the EPA of greenhouse gas emissions by such regulated facilities.
In April 2012, the EPA issued final rules that established new air emission controls for crude oil and natural gas production and natural gas processing operations. These rules were published in the Federal Register in August 2012. The EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with crude oil and natural gas production and processing activities. The final rules require the use of reduced emission completions or “green completions” on all hydraulically-fractured wells completed or refractured after January 1, 2015 in order to achieve a 95% reduction in the emission of VOCs. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules may require modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, and almost half of the states, including states in which we operate, have enacted or passed measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional

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greenhouse gas cap-and-trade programs. Most of these cap-and-trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. These reductions may cause the cost of allowances to escalate significantly over time.
The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or reduce emissions of greenhouse 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 and results of operations.
Finally, it should be noted some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur as a result of climate change or otherwise, they could have an adverse effect on our assets and operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and inability to book future reserves.
A significant majority of our operations utilize hydraulic fracturing, an important and commonly used process in the completion of crude oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the high-pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Some activists have attempted to link hydraulic fracturing to various environmental problems, including adverse effects to drinking water supplies as well as migration of methane and other hydrocarbons. As a result, several federal agencies are studying potential environmental risks with respect to hydraulic fracturing or evaluating whether to restrict its use. From time to time legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities from the definition of “underground injection,” thereby requiring the crude oil and natural gas industry to obtain permits for hydraulic fracturing, and to require disclosure of the additives used in the process. If ever adopted, such legislation could establish an additional level of regulation and permitting at the federal level.
Scrutiny of hydraulic fracturing activities continues in other ways. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing environmental issues associated with hydraulic fracturing. The EPA has commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the draft results of which are anticipated to be available in 2014. Further, in May 2012, the BLM issued a proposed rule 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. BLM published a supplemental notice of proposed rulemaking on May 24, 2013, which replaced the proposed rulemaking issued by the agency in May 2012. Additionally, on February 11, 2014 the EPA issued guidance governing the use of diesel fuel in hydraulic fracturing fluids. The guidance identifies five different variations of diesel and outlines new permitting guidelines for their use, along with technical recommendations for meeting the standards. As of December 31, 2013, we held approximately 183,200 net undeveloped acres on federal land, representing approximately 12% of our total net undeveloped acres. In addition to these federal initiatives, several state and local governments, including states in which we operate, have moved to require disclosure of fracturing fluid components or to otherwise regulate their use more closely. In certain areas of the United States, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards.
The adoption of any future federal, state or local law or implementing regulation imposing permitting or reporting obligations on, or otherwise limiting, the hydraulic fracturing process, or the discovery of groundwater contamination or other adverse environmental effects directly connected to hydraulic fracturing, could make it more difficult and more expensive to complete crude oil and natural gas wells in low-permeability formations and increase our costs of compliance and doing business, as well as delay, prevent or prohibit the development of natural resources from unconventional formations. In the event regulations are adopted that prohibit or significantly limit the use of hydraulic fracturing in states in which we operate, it would have a material adverse effect on our ability to economically find and develop crude oil and natural gas reserves in our strategic plays. The inability to achieve a satisfactory economic return could cause us to curtail or discontinue our exploration and development plans. Such a circumstance would have a material adverse effect on our business and would impair our ability to implement our growth plan.

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Should we fail to comply with FERC, FTC and CFTC administered statutes and regulations on market behavior, we could be subject to substantial penalties and fines and other liabilities.
The FERC, under the EPAct 2005, and the FTC, under the Energy Independence and Security Act of 2007, may impose or seek to impose through judicial action penalties for violations of anti-market manipulation rules for natural gas, crude oil and petroleum products of up to $1,000,000 per day for each violation. The CFTC, under the Commodity Exchange Act, has similar authority to assess penalties of up to the greater of $1,000,000 or triple the monetary gain for violation of anti-market manipulation rules for certain derivative contracts. Knowing or willful violations of the Commodity Exchange Act may also lead to a felony conviction. In addition, while we have not been regulated by the FERC as a natural gas company under the NGA, the FERC has adopted regulations that may subject us to the FERC annual reporting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC, the FTC or CFTC from time to time. Failure to comply with any of these regulations in the future could subject us to civil penalty liability, as well as the disgorgement of profits and third-party claims.
Proposed legislation and regulation under consideration could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.
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, regulation 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 described below, 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 and results of operations.
We presently transport a significant portion of operated crude oil production from our North region to market centers by rail, with approximately 70% of such production being shipped by rail in December 2013. In response to recent train derailments occurring in the United States and Canada in 2013, U.S. regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the NTSB issued a series of recommendations to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) to develop an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity of product carried on a train, and (iii) to audit shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the U.S. Department of Transportation issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of petroleum crude oil be handled as a Packing Group I or II hazardous material. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications or construction of rail cars used to transport crude oil could result in severe transportation capacity constraints during the period in which new rail cars are retrofitted or constructed to meet new specifications.
We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.
Certain federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of future legislation.
Among the changes contained in President Obama’s fiscal year 2014 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 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 2014 budget proposal or any other similar change in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to crude oil and natural gas exploration and development, and any such change could negatively affect our cash flows available for capital expenditures and our ability to achieve our growth plan.

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Regulations under the Dodd-Frank Act regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risk and other risks associated with our business.
We use derivative instruments to manage 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 that were then 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 when enacted may require us to post collateral, which could adversely affect our available liquidity. If we reduce our use of derivatives as a result of the regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position and results of operations.
Competition in the crude oil and natural gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing crude oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Certain of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our financial condition and results of operations.
The loss of senior management or technical personnel could adversely affect our operations.
We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As of December 31, 2013, non-operated properties represented 19% of our estimated proved developed reserves, 10% of our estimated proved undeveloped reserves, and 13% of our estimated total proved reserves. We have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures required to fund such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially adversely affect our financial condition and results of operations.

34



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 future goals.
Our credit facility and certain indentures for our senior notes include covenants and restrictions that may, among others, restrict:
our investments, loans and advances and the paying of dividends and other restricted payments;
our incurrence of additional indebtedness;
the granting of liens, other than liens created pursuant to the credit facility and certain permitted liens;
mergers, consolidations and sales of all or a substantial part of our business or properties;
the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities; and
the sale of assets.
Certain indentures for our outstanding senior notes may limit our ability and the ability of our restricted subsidiaries to:
incur, assume or guarantee additional indebtedness or issue redeemable stock;
pay dividends on stock, repurchase stock or redeem subordinated debt;
make certain investments;
enter into certain transactions with affiliates;
create certain liens on our assets;
sell or otherwise dispose of certain assets, including capital stock of subsidiaries;
restrict dividends, loans or other asset transfers from our restricted subsidiaries;
enter into new lines of business; and
consolidate with or merge with or into, or sell all or substantially all of our properties to another person.
Our credit facility also requires us to maintain certain financial ratios, such as leverage ratios.
The restrictive covenants in our credit facility and the senior note indentures may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our 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, such lenders or trustees could elect to declare 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 harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit ratings. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. For example, as of February 17, 2014, outstanding borrowings under our credit facility were $560 million and the impact of a 1% increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $5.6 million and a $3.5 million decrease in our annual net income. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and affiliates ($656.2 million in receivables at December 31, 2013), our joint interest receivables ($350.0 million at December 31, 2013), and counterparty credit risk associated with our derivative instrument receivables ($3.6 million at December 31, 2013). Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases included in units on

35



which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with several significant customers. The three largest purchasers of our crude oil and natural gas during the year ended December 31, 2013 accounted for a combined 38% of our total crude oil and natural gas revenues for the year. We generally do not require our counterparties to provide collateral to support crude oil and natural gas sales receivables owed to us. Additionally, our use of derivative instruments involves the risk that our counterparties will be unable to meet their obligations under the arrangements. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition and results of operations.
Our derivative activities could result in financial losses or reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of crude oil and natural gas, we enter into derivative instruments for a portion of our crude oil and/or natural gas production, including collars and fixed price swaps. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Crude Oil and Natural Gas Hedging and 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 the prices for crude oil and natural gas. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our crude oil and natural gas reserves. As part of our risk management program, we have hedged a significant portion of our forecasted production. We utilize a combination of derivative contracts based on West Texas Intermediate crude oil pricing, Inter-Continental Exchange pricing for Brent crude oil, and Henry Hub pricing for natural gas. We believe our derivative contracts provide relevant protection from price fluctuations in the U.S. markets where we deliver and sell our production. The pricing for Brent crude oil is believed to be a better reflection of the sales prices realized in certain U.S. market centers. However, in the event Brent prices increase significantly, the prices realized in those U.S. market centers may no longer be reflective of Brent prices. In such a circumstance, we may incur significant cash losses upon settling our crude oil derivative instruments. Such losses may be incurred without seeing a corresponding increase in revenues from higher realized prices on our physical sales of crude oil.
Our Chairman and Chief Executive Officer owns approximately 68% of our outstanding common stock, giving him influence and control in corporate transactions and other matters, including a sale of our Company.
As of December 31, 2013, Harold G. Hamm, our Chairman and Chief Executive Officer, beneficially owned 126,337,891 shares of our outstanding common stock representing approximately 68% of our outstanding common shares. As a result, Mr. Hamm is our controlling shareholder and will continue to be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other shareholders, the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. As controlling shareholder, Mr. Hamm could cause, delay or prevent a change of control of our Company. The interests of Mr. Hamm may not coincide with the interests of other holders of our common stock.
Several companies controlled by Mr. Hamm are 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, and expect to continue entering, into transactions from time to time with these affiliated companies if, after an independent review by our Audit Committee, it is determined such transactions are in the Company's best interests and are on terms no less favorable to us than could be achieved with an unaffiliated third party. These transactions may result in conflicts of interest between Mr. Hamm’s affiliated companies and us. We can provide no assurance that any such conflicts will be resolved in our favor.

36



We may be subject to risks in connection with acquisitions.
The successful acquisition of producing properties requires an assessment of several factors, including:
recoverable reserves;
future crude oil and natural gas prices and their differentials;
future development costs, operating costs and property taxes; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees and business associates, perform compliance reporting and in many other activities related to our business. Our business associates, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks, and those of our business associates may 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 the following ways, among others:
unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas 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.

37





Item 1B.
Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2013.
 
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. 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.

38



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. No cash dividends were declared during the previous two years. 
 
 
2013
 
2012
 
 
Quarter Ended
 
Quarter Ended
 
 
March 31
 
June 30
 
September 30
 
December 31
 
March 31
 
June 30
 
September 30
 
December 31
High
 
$
93.99

 
$
89.63

 
$
108.19

 
$
121.78

 
$
97.19

 
$
91.82

 
$
84.19

 
$
80.59

Low
 
$
74.03

 
$
72.35

 
$
86.56

 
$
100.25

 
$
67.94

 
$
61.50

 
$
61.02

 
$
66.07

Cash Dividend
 

 

 

 

 

 

 

 

Certain of our senior note indentures restrict the payment of dividends under certain circumstances and we do not anticipate paying any cash dividends on our common stock in the foreseeable future. As of February 17, 2014, the number of record holders of our common stock was 126. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately 57,200. On February 17, 2014, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $113.27 per share.
The following table summarizes our purchases of our common stock during the quarter ended December 31, 2013:
 
Period
 
Total number of
shares purchased
 
Average
price paid
per share
 
Total number of shares
purchased as part of
publicly announced
plans or programs
 
Maximum number of
shares that may yet be
purchased under the
plans or programs (3)
October 1, 2013 to October 31, 2013
 

 

 

 

November 1, 2013 to November 30, 2013
 
92,303

(1)
$
116.45

(1)

 

December 1, 2013 to December 31, 2013
 
41,000

(2)
$
102.20

(2)

 

Total
 
133,303

 
$
112.07

 

 

 
(1)
In connection with 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. Effective May 23, 2013, the 2013 Plan was adopted and replaced the Company's 2005 Plan. Restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will