10-K 1 a201610-k.htm 2016 10-K Document


 
 
 
 
 
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, 2016
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
_______________________________ 
logoa01a03.jpg
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, 2016 was approximately $3.9 billion, based upon the closing price of $45.27 per share as reported by the New York Stock Exchange on such date.
374,483,998 shares of our $0.01 par value common stock were outstanding on January 31, 2017.

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 2017, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Form 10-K.
 
 
 
 
 




Table of Contents 
 
 
 
PART I
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
PART II
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
PART III
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
PART IV
 
 
Item 15.





Glossary of Crude Oil and Natural Gas Terms
The terms defined in this section may be used throughout this report:
“basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Bcf” One billion cubic feet of natural gas.
“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.
“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
“conventional play” An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.
“DD&A” Depreciation, depletion, amortization and accretion.
de-risked” Refers to acreage and locations in which the Company believes the geological risks and uncertainties related to recovery of crude oil and natural gas have been reduced as a result of drilling operations to date. However, only a portion of such acreage and locations have been assigned proved undeveloped reserves and ultimate recovery of hydrocarbons from such acreage and locations remains subject to all risks of recovery applicable to other acreage.
“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.
“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry gas” Refers to natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also may refer to gas that has been processed or treated to remove all natural gas liquids.
“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.
“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 crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“formation” A layer of rock which has distinct characteristics that differs from nearby rock.
“fracture stimulation” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Also may be referred to as hydraulic fracturing.
"gross acres" or "gross wells" Refers to the total acres or wells in which a working interest is owned.
“held by production” or “HBP” Refers to an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.
“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.

i



“MBoe” One thousand Boe.
“Mcf” One thousand cubic feet of natural gas.
“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.
“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 per-well drilling and completion costs.
“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 completion.
“PV-10” When used with respect to crude oil and natural gas reserves, PV-10 represents the estimated future gross revenues to be generated from the production of proved reserves using a 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December, net of estimated production and future development and abandonment costs based on costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities and Exchange Commission (“SEC”). PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company’s crude oil and natural gas properties. The Company and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“resource play” Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.
“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 used to describe properties located in the Anadarko basin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.

ii



“STACK” Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma. Historically, our properties in those counties that produced from the Woodford formation were referred to as the Northwest Cana district, while properties often underlying the same surface acreage that produced from the Meramec and Osage formations were referred to as the STACK district. Such properties were historically combined by us and referred to as "Northwest Cana/STACK". Effective December 31, 2016, we now refer to such properties simply as "STACK".
“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 net cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis in the crude oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“step-out well” or “step outs” A well drilled beyond the proved boundaries of a field to investigate a possible extension of the field.
“three dimensional (3D) seismic” Seismic surveys using an instrument to send sound waves into the earth and collect data to help geophysicists define the underground configurations. 3D seismic provides three-dimensional pictures. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We also use 3D seismic to identify sub-surface hazards to assist in steering, avoiding hazards and determining where to perform enhanced completions.
“unconventional play” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production. In general, unconventional plays require the application of more advanced technology and higher drilling and completion costs to produce relative to conventional plays.
“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“well bore” The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called a well or borehole.
“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

iii



Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include, but are not limited to, statements about:
our strategy;
our business and financial plans;
our future operations;
our crude oil and natural gas reserves and related development plans;
technology;
future 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;
property 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 and financial results;
our future commodity or other hedging arrangements; and
the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.
Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors and elsewhere in this report, registration statements we file from time to time with the Securities and Exchange Commission, 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 on which such statement is made. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.
Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

iv



Part I
You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “Continental,” “we,” “us,” “our,” “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiaries.
 
Item 1.
Business
General
We are an independent crude oil and natural gas 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 all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), and Arkoma Woodford areas of Oklahoma. Historically, our properties in Blaine, Dewey and Custer counties of Oklahoma that produced from the Woodford formation were referred to as the Northwest Cana district, while properties often underlying the same surface acreage in those counties that produced from the Meramec and Osage formations were referred to as the STACK district. Such properties were historically combined by us and referred to as "Northwest Cana/STACK". Effective December 31, 2016, we now refer to such properties simply as "STACK". The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations.
We were originally formed in 1967 to explore for, develop and produce crude oil and natural gas properties. Through the late 1980s, our activities and growth remained focused primarily in Oklahoma. In the late 1980s, we expanded our activity into the North region. The North region comprised approximately 61% of our crude oil and natural gas production and approximately 69% of our crude oil and natural gas revenues for the year ended December 31, 2016. Approximately 50% of our estimated proved reserves as of December 31, 2016 are located in the North region. In recent years, we have significantly expanded our activity in our South region with our discovery of the SCOOP play and our increased activity in the STACK play. Our South region comprised approximately 39% of our crude oil and natural gas production, 31% of our crude oil and natural gas revenues, and 50% of our estimated proved reserves as of and for the year ended December 31, 2016.
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 develop and produce crude oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drill bit.
As of December 31, 2016, our estimated proved reserves were 1,275 MMBoe, with estimated proved developed reserves of 519 MMBoe, or 41% of our total estimated proved reserves. Crude oil represents approximately 50% of our estimated proved reserves as of December 31, 2016. The standardized measure of our discounted future net cash flows totaled approximately $5.5 billion at December 31, 2016.
For 2016, we generated crude oil and natural gas revenues of $2.03 billion and operating cash flows of $1.13 billion. Crude oil accounted for approximately 59% of our total production and approximately 82% of our crude oil and natural gas revenues for 2016. Production averaged 216,912 Boe per day for 2016, a 2% decrease compared to average production of 221,715 Boe per day for 2015. Average daily production for the quarter ended December 31, 2016 decreased 7% to 209,861 Boe per day compared to 224,936 Boe per day for the quarter ended December 31, 2015, reflecting natural declines in production, reduced drilling and completion activities, and persistent severe winter weather in North Dakota in late 2016.
The table below summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2016, average daily production for the quarter ended December 31, 2016 and the reserve-to-production index in our principal operating areas. The PV-10 values shown below are not intended to represent the fair market value of our crude oil and natural gas properties. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. See Part I, Item 1A. Risk Factors and “Critical Accounting Policies and Estimates” in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report for further discussion of uncertainties inherent in the reserve estimates. 

1



 
 
December 31, 2016
 
Average daily
production for
fourth quarter
2016
(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
 
552,965

 
43.4
%
 
$
3,492

 
1,187

 
96,035

 
45.8
%
 
15.8

Montana Bakken
 
38,936

 
3.1
%
 
261

 
265

 
8,489

 
4.0
%
 
12.6

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
35,502

 
2.8
%
 
354

 
130

 
7,572

 
3.6
%
 
12.8

Other Red River units
 
2,470

 
0.2
%
 
20

 
117

 
2,568

 
1.2
%
 
2.6

Other
 
1,223

 
0.1
%
 
6

 
8

 
4,109

 
2.0
%
 
0.8

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
471,921

 
37.0
%
 
1,910

 
244

 
63,490

 
30.3
%
 
20.4

STACK
 
161,243

 
12.6
%
 
574

 
94

 
24,426

 
11.6
%
 
18.1

Arkoma Woodford
 
6,796

 
0.5
%
 
21

 
54

 
1,929

 
0.9
%
 
9.7

Other
 
3,808

 
0.3
%
 
17

 
207

 
1,243

 
0.6
%
 
8.4

Total
 
1,274,864

 
100.0
%
 
$
6,655

 
2,306

 
209,861

 
100.0
%
 
16.6

 
(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 $1.1 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. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for further discussion.
(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 2016 production into estimated proved reserve volumes as of December 31, 2016.
Business Environment and Outlook
Crude oil prices faced significant downward pressure in early 2016 due to domestic and global supply and demand factors, with prices dropping to $26 per barrel in February 2016, a level not seen since 2003. Natural gas prices also faced significant downward pressure in early 2016, dropping to $1.49 per MMBtu in March 2016, a level not seen since 1998. Commodity prices subsequently showed signs of stabilization and improvement in late 2016, with crude oil prices reaching $54 per barrel and natural gas prices reaching $3.80 per MMBtu in December 2016.
Commodity prices remain volatile and unpredictable and it is uncertain whether the increase in market prices experienced in recent months will be sustained. In light of this uncertainty, our primary business strategies for 2017 will focus on: (1) high-grading investments based on rates of return and opportunities to work down our large inventory of drilled but uncompleted wells and convert undeveloped acreage to acreage held by production, (2) optimizing cash flows through operating efficiencies, cost reductions, and enhanced completions, (3) managing capital spending to minimize the incurrence of new debt and maintain ample liquidity and financial flexibility, and (4) further reducing debt using proceeds from potential sales of non-strategic assets.
In response to the stabilization and improvement in commodity prices in late 2016 we have increased our planned non-acquisition capital spending for 2017 to $1.95 billion compared to $1.07 billion spent in 2016. This planned investment level has been set based on an expectation of available cash flows for 2017 at an assumed average West Texas Intermediate benchmark crude oil price of $55 per barrel and an assumed average Henry Hub benchmark price of $3.14 per Mcf for the year.

2



As part of our planned increase in spending for 2017, we expect to increase our well completion activities and begin to work down our large year-end 2016 inventory of uncompleted wells in North Dakota. Starting in late 2015, we significantly reduced our Bakken well completion activities in response to depressed crude oil prices and shifted our focus to higher rate-of-return areas in Oklahoma that typically have higher concentrations of natural gas. As a result of this shift, our inventory of uncompleted wells in North Dakota Bakken grew to 187 gross (138 net) operated wells at December 31, 2016 and natural gas grew to become a larger portion of our total production and revenues in 2016 compared to our historical results. During 2016, we worked to test and develop the best enhanced completion methods to improve production and reserve potential. For 2017, we expect to begin realizing the value from those efforts in conjunction with our increased well completion activities.
Approximately $550 million of our 2017 capital budget is expected to be allocated toward the completion of operated and non-operated North Dakota Bakken wells that were drilled but not completed as of year-end 2016, which is expected to reduce our operated uncompleted well inventory in that play by 131 gross (100 net) operated wells in 2017. Additionally, in 2017 we plan to spend approximately $226 million to drill 101 gross (57 net) new operated Bakken wells, of which 17 gross (8 net) wells are expected to have first production in 2017, and $264 million on new non-operated Bakken drilling. Further, in 2017 we plan to spend approximately $435 million primarily in oil-weighted areas of the STACK play and $245 million in the SCOOP play. This planned allocation of capital is expected to result in crude oil becoming a larger portion of our total production as 2017 progresses. Crude oil is projected to account for approximately 59% of our total production by year-end 2017 compared to approximately 55% in the fourth quarter of 2016.
Our increased drilling and completion activities are projected to result in an increase in our average daily production from 216,912 Boe per day for 2016 to between 220,000 and 230,000 Boe per day for 2017. Our rate of production is expected to be relatively flat through the first half of 2017 relative to year-end 2016, but is expected to accelerate in the second half of the year due to production commencing from our Bakken well completion activities. Our inventory of uncompleted wells represents significant value to Continental and our increased completion activities are expected to be a key driver of our production and cash flow growth in 2017. We plan to be disciplined, however, and may adjust our pace of development as 2017 market conditions evolve. See the section below titled Summary of Crude Oil and Natural Gas Properties and Projects for further discussion of our 2017 plans.
Our Business Strategy
Despite ongoing volatility and uncertainty in commodity prices, our business strategy continues to be focused on increasing shareholder value by finding and developing crude oil and natural gas reserves at costs that provide attractive rates of return. The principal elements of this strategy include:
Growing and sustaining a premier portfolio of assets focused on high rate-of-return projects. We hold a portfolio of leasehold acreage, drilling opportunities and uncompleted wells in certain premier U.S. resource plays with varying exposure to crude oil, natural gas, and natural gas liquids. We pursue opportunities to develop our existing properties as well as explore for new resource plays where significant reserves may be economically developed. Our capital programs are designed to allocate investments to projects that provide opportunities to work down our large inventory of uncompleted wells, convert our undeveloped acreage to acreage held by production, and improve hydrocarbon recoveries and rates of return on capital employed. While our operations have historically focused on the exploration and development of crude oil, we also allocate significant capital to liquids-rich natural gas areas that provide attractive rates of return.
Optimizing cash flows through operating efficiencies, cost reductions, and enhanced completions. We continue to manage through the current commodity price environment by focusing on improving operating efficiencies and reducing costs. Our key operating areas are characterized by large acreage positions in select unconventional resource plays with multiple stacked geologic formations that provide repeatable drilling opportunities and resource potential. We operate a significant portion of our wells and leasehold acreage and believe the concentration of our operated assets allows us to leverage our technical expertise and manage the development of our properties to achieve cost reductions through operating efficiencies and economies of scale.
Building upon progress made in 2015, we continued to achieve large efficiency gains in various aspects of our business in 2016, including additional reductions in spud-to-total depth drilling times and average days to drill horizontal laterals, which led to significant reductions in drilling costs in our core areas incremental to those achieved in 2015. In addition to lowering our drilling costs, we also work to optimize cash flows through the use of enhanced completion technologies that help improve recoveries and rates of return. These efforts have had a positive impact on the efficiency of our capital deployed in recent years, resulting in significant improvement in the quantity of reserves found and developed per dollar invested.
Maintaining financial flexibility and a strong balance sheet. Maintaining a strong balance sheet, ample liquidity, and financial flexibility are key components of our business strategy. In 2016, we reduced our total debt by $538 million, or 8%, from $7.12 billion at year-end 2015 to $6.58 billion at year-end 2016. For 2017, we are targeting further debt reduction using proceeds

3



from potential sales of non-strategic assets and will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. As we have done historically to preserve or enhance liquidity we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.
Focusing on organic growth through disciplined capital investments. Although we consider various growth opportunities, including property acquisitions, our primary focus is on organic growth through leasing and drilling in our core areas where we can exploit our extensive inventory of repeatable drilling opportunities to achieve attractive rates of return. From January 1, 2014 through December 31, 2016, our proved reserve additions through organic extensions and discoveries were 943 MMBoe compared to 1 MMBoe of proved reserve acquisitions during that same period.
Our Business Strengths
We have a number of strengths we believe will help us successfully execute our business strategy, including the following:
Large Acreage Inventory. We held approximately 786,800 net undeveloped acres and 1.18 million net developed acres under lease in certain premier U.S. resource plays as of December 31, 2016. Approximately 60% of our net undeveloped acres are located within unconventional resource plays in the Bakken, SCOOP, STACK and Arkoma Woodford areas. We have developed sizable acreage positions in our core operating areas and believe the concentration of our assets allows us to achieve operating efficiencies and reduce costs through economies of scale. We are among the largest leaseholders in the Bakken, SCOOP, and STACK plays with approximately 848,500 net acres, 345,700 net acres, and 196,200 net acres under lease in those respective plays at December 31, 2016. Being an early entrant in these plays has allowed us to capture significant acreage positions in core parts of the plays.
Expertise with Horizontal Drilling and Enhanced Completion Methods. We have substantial experience with horizontal drilling and enhanced completion methods and continue to be among the industry leaders in the use of new drilling and completion technologies. We continue to improve drilling and completion efficiencies through the use of multi-well pad drilling in our operating areas. Further, we are among industry leaders in drilling long lateral lengths. Results to date indicate longer laterals have a positive impact on well productivity and economics. We have also been among industry leaders in testing enhanced completion technologies involving various combinations of fluid types, proppant types and volumes, and stimulation stage lengths to determine optimal methods for improving recoveries and rates of return. We continually refine our drilling and completion techniques in an effort to deliver improved results across our properties.
Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2016, we operated properties comprising 88% of our total proved reserves. By controlling a significant portion of our operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and completion methods used.
Experienced Management Team. Our senior management team has extensive expertise in the oil and gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 10 senior officers have an average of 37 years of oil and gas industry experience.
Financial Position and Liquidity. We have a revolving credit facility with lender commitments totaling $2.75 billion which may be increased up to a total of $4.0 billion upon agreement with participating lenders to provide additional liquidity if needed to take advantage of business opportunities and fund our capital program and commitments. We had approximately $1.91 billion of available borrowing capacity under our credit facility at January 31, 2017 after considering outstanding borrowings and letters of credit. We have no near-term debt maturities, with our earliest maturity being a $500 million term loan due in November 2018.
Our revolving credit facility is unsecured and does not have a borrowing base requirement that is subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current revolving credit facility commitments, nor do such actions trigger a security requirement or change in covenants. Downgrades of our credit rating will, however, trigger increases in our revolving credit facility's interest rates and commitment fees paid on unused borrowing availability under certain circumstances.

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 Company, L.P (“Ryder Scott”), our independent reserve engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole and production data, seismic data and well test data.
The following table sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2016. The standardized measure of our discounted future net cash flows totaled approximately $5.5 billion at December 31, 2016. Our reserve estimates as of December 31, 2016 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 99% of our PV-10 and 99% of our total proved reserves as of December 31, 2016. Our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K.  
Our estimated proved reserves and related future net revenues, Standardized Measure and PV-10 at December 31, 2016 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2016 through December 2016, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $42.75 per Bbl for crude oil and $2.49 per MMBtu for natural gas ($35.57 per Bbl for crude oil and $2.14 per Mcf for natural gas adjusted for location and quality differentials).
 
 
Crude Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
 
PV-10 (1)
(in millions)
Proved developed producing
 
289,142

 
1,366,461

 
516,885

 
$
4,611.8

Proved developed non-producing
 
1,068

 
4,159

 
1,761

 
10.5

Proved undeveloped
 
353,018

 
2,419,198

 
756,218

 
2,032.8

Total proved reserves
 
643,228

 
3,789,818

 
1,274,864

 
$
6,655.1

Standardized Measure (1)
 
 
 
 
 
 
 
$
5,510.2

 
(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 $1.1 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. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for further discussion.

5



The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2016. 
 
 
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
 
185,017

 
367,560

 
246,277

 
232,506

 
445,091

 
306,688

Montana Bakken
 
21,072

 
34,155

 
26,764

 
10,545

 
9,765

 
12,172

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
34,356

 
6,878

 
35,502

 

 

 

Other Red River units
 
2,371

 
593

 
2,470

 

 

 

Other
 
84

 
6,832

 
1,223

 

 

 

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
37,933

 
677,448

 
150,841

 
77,991

 
1,458,532

 
321,080

STACK
 
8,557

 
218,447

 
44,965

 
31,976

 
505,810

 
116,278

Arkoma Woodford
 
3

 
40,758

 
6,796

 

 

 

Other
 
817

 
17,949

 
3,808

 

 

 

Total
 
290,210

 
1,370,620

 
518,646

 
353,018

 
2,419,198

 
756,218

The following table provides information regarding changes in total estimated proved reserves for the periods presented.  
 
 
Year Ended December 31,
MBoe
 
2016
 
2015
 
2014
Proved reserves at beginning of year
 
1,225,811

 
1,351,091

 
1,084,125

Revisions of previous estimates
 
(110,474
)
 
(297,198
)
 
(107,949
)
Extensions, discoveries and other additions
 
249,430

 
253,173

 
440,621

Production
 
(79,390
)
 
(80,926
)
 
(63,579
)
Sales of minerals in place
 
(10,513
)
 
(329
)
 
(3,227
)
Purchases of minerals in place
 

 

 
1,100

Proved reserves at end of year
 
1,274,864

 
1,225,811

 
1,351,091

Revisions of previous estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs.

The downward pressure on commodity prices experienced in recent years intensified in early 2016, with crude oil prices dropping to $26 per barrel in February 2016 and natural gas prices dropping to $1.49 per MMBtu in March 2016. Prices remained depressed for a significant portion of 2016, resulting in a decrease in the 12-month average prices used to estimate proved reserves at year-end 2016. The 12-month average price for crude oil decreased 15% from $50.28 per Bbl for 2015 to $42.75 per Bbl for 2016, while the 12-month average price for natural gas decreased 3% from $2.58 per MMBtu for 2015 to $2.49 per MMBtu for 2016. These decreases shortened the economic lives of certain producing properties and caused certain exploration and development projects to become uneconomic which had an adverse impact on our proved reserve estimates, resulting in downward reserve revisions of 20 MMBo and 50 Bcf (totaling 28 MMBoe) in 2016.
Given the drastic decrease in commodity prices in early 2016, and given the uncertainty regarding the timing and magnitude of any price recovery, maintaining a strong balance sheet, ample liquidity, and financial flexibility has become an increasingly important component of our long-term business strategy. We significantly reduced our capital spending in 2016 to minimize the incurrence of new debt. Similarly, our 2017 capital budget has been set based on an expectation of available cash flows.
In light of our strategy to preserve liquidity and financial flexibility, we have further refined our capital program to focus on areas that provide the greatest opportunities to convert undeveloped acreage to acreage held by production, achieve operating efficiencies and cost reductions through multi-well pad drilling, and improve recoveries, cash flows and rates of return using

6



enhanced completions. As part of this effort, we shifted a significant portion of our 2016 spending away from the Bakken to areas in Oklahoma that offered more advantageous opportunities. We expect to continue allocating significant capital to Oklahoma given the drilling successes achieved to date in the STACK and SCOOP plays. This shift, a longer and more severe decrease in crude oil prices than anticipated, and our increased emphasis on balancing capital spending with cash flows have altered the timing and extent of our previous development plans in certain areas and resulted in the removal of 51 MMBo and 118 Bcf (totaling 70 MMBoe) of PUD reserves no longer scheduled to be developed within five years from the date of initial booking, primarily in the Bakken. These removals do not necessarily represent the elimination of recoverable hydrocarbons physically in place. In some instances the removed reserves may be developed in the future in the event of a favorable change in commodity prices and an expansion of our capital expenditure budget.
Additionally, changes in anticipated production performance on certain properties resulted in 37 MMBo of downward revisions to crude oil reserves and 166 Bcf of upward revisions to natural gas reserves (netting to 9 MMBoe of downward revisions) in 2016. Further, changes in ownership interests, operating costs, and other factors during the year resulted in 7 MMBo of upward revisions to crude oil reserves and 61 Bcf of downward revisions to natural gas reserves (netting to 3 MMBoe of downward revisions).
Extensions, discoveries and other additions. These are additions to our proved reserves that result from (i) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling activity in the Bakken, SCOOP and STACK areas. Proved reserve additions from our drilling activities in the Bakken totaled 73 MMBoe, 96 MMBoe and 222 MMBoe for 2016, 2015 and 2014, respectively, while reserve additions in SCOOP totaled 97 MMBoe, 93 MMBoe and 208 MMBoe for 2016, 2015 and 2014, respectively. Additionally, extensions and discoveries in 2016 and 2015 were significantly impacted by successful drilling results in the STACK play, resulting in proved reserve additions of 79 MMBoe in 2016 and 57 MMBoe in 2015. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2016 drilling activities. We expect a significant portion of future reserve additions will continue to come from our major development projects in the Bakken, SCOOP, and STACK areas.
Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 14. Property Dispositions for further discussion of notable dispositions. We may continue to seek opportunities to sell non-strategic properties if and when we have the ability to dispose of such assets at favorable terms.
Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a period. We have had no significant acquisitions in the past three years. However, we may participate as a buyer of properties when and if we have the ability to increase our position in strategic plays at favorable terms.
Proved Undeveloped Reserves
All of our PUD reserves at December 31, 2016 are located in the SCOOP, Bakken, and STACK plays, our most active development areas, with those plays comprising 43%, 42%, and 15%, respectively, of our total PUD reserves at year-end 2016. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2016. Our PUD reserves at December 31, 2016 include 81 MMBoe of reserves associated with drilled but uncompleted wells.
 
 
Crude Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
Proved undeveloped reserves at December 31, 2015
 
373,716

 
1,961,443

 
700,623

Revisions of previous estimates
 
(81,305
)
 
(123,838
)
 
(101,945
)
Extensions and discoveries
 
80,397

 
757,554

 
206,656

Sales of minerals in place
 
(896
)
 
(2,047
)
 
(1,237
)
Purchases of minerals in place
 

 

 

Conversion to proved developed reserves
 
(18,894
)
 
(173,914
)
 
(47,879
)
Proved undeveloped reserves at December 31, 2016
 
353,018

 
2,419,198

 
756,218

Revisions of previous estimates. During the year ended December 31, 2016, we removed 255 gross (141 net) PUD locations, which resulted in the removal of 51 MMBo and 118 Bcf (totaling 70 MMBoe) of PUD reserves, of which 47 MMBo and 75 Bcf (totaling 60 MMBoe) was related to our Bakken properties. These removals were due to the aforementioned refinement of our drilling program to place emphasis on areas that provide the greatest opportunities to convert undeveloped acreage to

7



acreage held by production, achieve operating efficiencies and cost reductions through multi-well pad drilling, and improve recoveries, cash flows and rates of return using enhanced completions. These and other aforementioned factors altered the timing and extent of our previous development plans in certain areas and resulted in the removal of PUD reserves no longer scheduled to be developed within five years of the date of initial booking.
Additionally, decreases in crude oil and natural gas prices in 2016 caused certain exploration and development projects to become uneconomic, which resulted in downward PUD reserve revisions of 9 MMBo and 26 Bcf (totaling 13 MMBoe) in 2016. Further, changes in anticipated production performance on producing properties having offsetting PUD locations resulted in 22 MMBo of downward revisions to crude oil PUD reserves and 60 Bcf of upward revisions to natural gas PUD reserves (netting to 12 MMBoe of downward revisions) in 2016. Finally, changes in ownership interests, operating costs, and other factors during the year resulted in a net decrease in PUD reserves of 40 Bcf (7 MMBoe).
Extensions and discoveries. Extensions and discoveries were primarily due to increases in PUD reserves associated with our successful drilling activity in the Bakken, SCOOP and STACK areas. PUD reserve additions in the Bakken totaled 45 MMBo and 84 Bcf (totaling 59 MMBoe) in 2016, while SCOOP PUD reserve additions totaled 14 MMBo and 383 Bcf (totaling 78 MMBoe), and STACK PUD reserve additions totaled 21 MMBo and 290 Bcf (totaling 70 MMBoe). See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2016 drilling activities in these areas.
Conversion to proved developed reserves. In 2016, we developed approximately 10% of our PUD locations and 7% of our PUD reserves booked as of December 31, 2015 through the drilling and completion of 192 gross (60 net) development wells at an aggregate capital cost of approximately $269 million. In 2015 and 2016, we significantly reduced our well completion activities in response to depressed crude oil prices. These actions resulted in a build up of drilled but uncompleted wells at year-end 2015 that subsequently grew in 2016, which adversely impacted our conversion of PUD reserves to proved developed reserves in 2016. Our drilled but uncompleted wells are classified as PUD reserves when relatively major expenditures are required to complete the wells.
At December 31, 2015, we had 91 MMBoe of PUD reserves associated with 179 gross (125 net) operated uncompleted PUD locations at that date, a majority of which were not completed in 2016 and, accordingly, are not reflected as having been converted to proved developed reserves in 2016 and continue to be reflected as PUD locations at December 31, 2016. If the year-end 2015 drilled but uncompleted wells had been completed and converted to proved developed locations in 2016, our 2016 PUD reserve conversion rate of 7% would have been notably higher.
Our inventory of drilled but uncompleted wells now totals 187 gross (138 net) operated wells in North Dakota and 43 gross (19 net) operated wells in Oklahoma at December 31, 2016. As previously noted, in 2017 we plan to increase our well completion activities and work down a significant portion of our uncompleted PUD locations. These actions are expected to have a positive impact on our PUD conversion rate in 2017. PUD reserves associated with drilled but uncompleted wells totaled 81 MMBoe at December 31, 2016, representing 11% of our total PUD reserves at that date.
Development plans. We have acquired substantial leasehold positions in the Bakken, SCOOP and STACK plays. Our drilling programs to date in those areas have focused on proving our undeveloped leasehold acreage through strategic 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 may opportunistically drill strategic exploratory wells, the majority of our future capital expenditures will be focused on developing our PUD locations, with emphasis on drilled but not completed locations. The costs to drill our uncompleted wells were incurred prior to December 31, 2016 and only the remaining completion costs are included in future development plans.
Estimated future development costs relating to the development of PUD reserves are projected to be approximately $1.1 billion in 2017 (56% of total capital budget), $1.4 billion in 2018, $1.5 billion in 2019, $1.3 billion in 2020, and $1.0 billion in 2021. These capital expenditure projections are reflective of the current commodity price environment and have been established based on an expectation of available cash flows and borrowing capacity. Development of our existing PUD reserves at December 31, 2016, including those associated with uncompleted wells, is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be developed within five years of initial booking because of depressed commodity prices or for other reasons have been removed from our reserves at December 31, 2016. We had no PUD reserves at December 31, 2016 that remain undeveloped beyond five years from the date of initial booking.

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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 and 99% of our total proved reserves as of December 31, 2016 included in this Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Form 10-K for further discussion of the qualifications of Ryder Scott personnel.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team is in contact regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserve estimates. Proved reserve information is reviewed by our Audit Committee with representatives of Ryder Scott and by our internal technical staff before the information is filed with the SEC on Form 10-K. Additionally, certain members of our senior management review and approve the Ryder Scott reserve report and on a semi-annual basis review any internal proved reserve estimates.
Our Vice President—Corporate Reserves 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 32 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 Reserves reports directly to our Vice Chairman of Strategic Growth Initiatives. The reserve estimates are reviewed and approved by the President and Chief Operating Officer and certain other members of senior management.
Proved Reserve, Standardized Measure, and PV-10 Sensitivities
Our year-end 2016 proved reserve, Standardized Measure, and PV-10 estimates were prepared using 2016 average prices of $42.75 per Bbl for crude oil and $2.49 per MMBtu for natural gas. Actual future prices may be materially higher or lower than those used in our year-end estimates. Commodity prices existing through February 17, 2017 are higher than the 2016 average prices.
Provided below are sensitivities illustrating the potential impact on our estimated proved reserves, Standardized Measure, and PV-10 at December 31, 2016 under different commodity price scenarios for crude oil and natural gas. In these sensitivities, all factors other than the commodity price assumption have been held constant for each well. These sensitivities demonstrate the impact that changing commodity prices may have on estimated proved reserves, Standardized Measure, and PV-10 and there is no assurance these outcomes will be realized.

The crude oil price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under various crude oil price scenarios, with natural gas prices being held constant at the 2016 average price of $2.49 per MMBtu.

9



a201510-k_chartx36463a01.jpg

10



The natural gas price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under various natural gas price scenarios, with crude oil prices being held constant at the 2016 average price of $42.75 per Bbl.
a201510-k_chartx39414a01.jpg
Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2016: 
 
 
Developed acres
 
Undeveloped acres
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
945,721

 
553,758

 
185,958

 
104,807

 
1,131,679

 
658,565

Montana Bakken
 
170,497

 
137,799

 
94,097

 
52,156

 
264,594

 
189,955

Red River units
 
159,429

 
139,056

 
32,411

 
16,172

 
191,840

 
155,228

Other
 
102,730

 
64,334

 
129,160

 
85,286

 
231,890

 
149,620

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
213,317

 
124,818

 
404,406

 
220,925

 
617,723

 
345,743

STACK
 
174,589

 
104,226

 
179,166

 
91,963

 
353,755

 
196,189

Arkoma Woodford
 
110,590

 
26,244

 
4,545

 
669

 
115,135

 
26,913

Other
 
65,710

 
33,968

 
82,263

 
27,668

 
147,973

 
61,636

East Region
 

 

 
210,809

 
187,144

 
210,809

 
187,144

Total
 
1,942,583

 
1,184,203

 
1,322,815

 
786,790

 
3,265,398

 
1,970,993



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The following table sets forth the number of gross and net undeveloped acres as of December 31, 2016 scheduled to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates or the leases are renewed. 
 
 
2017
 
2018
 
2019
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
72,085

 
40,034

 
19,477

 
13,020

 
2,500

 
1,608

Montana Bakken
 
55,099

 
32,996

 
14,126

 
9,489

 
400

 
400

Red River units
 
6,953

 
3,227

 
4,797

 
3,318

 
2,879

 
1,365

Other
 
20,378

 
13,997

 
9,264

 
6,078

 
20,097

 
13,877

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
202,235

 
103,748

 
66,636

 
42,795

 
51,329

 
30,993

STACK
 
24,780

 
11,820

 
53,646

 
28,789

 
70,416

 
36,657

Arkoma Woodford
 

 

 

 

 
1,157

 
492

Other
 
43,787

 
17,049

 
2,472

 
581

 
5,734

 
4,872

East Region
 
54,479

 
52,775

 
7,206

 
6,527

 
55,355

 
40,432

Total
 
479,796

 
275,646

 
177,624

 
110,597

 
209,867

 
130,696


Drilling Activity
During the three years ended December 31, 2016, we drilled and completed exploratory and development wells as set forth in the table below:
 
 
2016
 
2015
 
2014
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
39

 
11.4

 
28

 
19.8

 
94

 
70.5

Natural gas
 
15

 
4.2

 
19

 
1.4

 
42

 
8.3

Dry holes
 

 

 
1

 
1.0

 
3

 
1.6

Total exploratory wells
 
54

 
15.6

 
48

 
22.2

 
139

 
80.4

Development wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
245

 
54.7

 
707

 
215.5

 
897

 
290.3

Natural gas
 
66

 
21.6

 
142

 
32.8

 
64

 
16.8

Dry holes
 

 

 

 

 
1

 
1.0

Total development wells
 
311

 
76.3

 
849

 
248.3

 
962

 
308.1

Total wells
 
365

 
91.9

 
897

 
270.5

 
1,101

 
388.5

As of December 31, 2016, there were 440 gross (198 net) operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.
For 2017, we plan to operate an average of approximately 20 drilling rigs and 11 completion crews for the year. Our drilling and completion activity for 2017 will depend on crude oil and natural gas prices and potential drilling efficiency gains and, accordingly, our rig and completion crew count may increase or decrease from planned levels. As a result of the significant decrease in commodity prices in recent years, the number of providers of materials and services has decreased in the regions where we operate. As a result, the likelihood of experiencing shortages of materials and services may be further increased in connection with any period of commodity price recovery. See Part I, Item 1A. Risk Factors—The unavailability or high cost of drilling rigs, well completion crews, 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.

12



Summary of Crude Oil and Natural Gas Properties and Projects
In the following discussion, we review our budgeted number of wells and capital expenditures for 2017 in our key operating areas. Our 2017 capital budget has been set based on an expectation of available cash flows in order to minimize the incurrence of new debt. If cash flows are materially impacted by a decline in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our revolving credit facility if needed to fund our operations. Conversely, higher cash flows resulting from an increase in commodity prices could result in increased capital expenditures.
The following table provides information regarding well counts and 2017 budgeted capital expenditures by operating area.
 
 
2017 Plan
 
 
Gross wells (1)
 
Net wells (1)
 
Capital expenditures 
(in millions)
 
 
North Region:
 
 
 
 
 
 
Bakken (2)
 
351

 
143

 
$
1,040

South Region:
 
 
 
 
 
 
SCOOP
 
108

 
24

 
245

STACK
 
157

 
51

 
435

Total exploration and development drilling
 
616

 
218

 
$
1,720

Land
 
 
 
 
 
115

Capital facilities, workovers and other corporate assets
 
 
 
 
 
105

Seismic
 
 
 
 
 
10

Total 2017 capital budget, excluding acquisitions
 
 
 
 
 
$
1,950

(1)
Represents wells expected to have first production in 2017.
(2)
2017 budget includes $550 million for the completion of operated and non-operated North Dakota Bakken wells that were drilled but not completed as of year-end 2016.
North Region
Our properties in the North region represented 50% of our total proved reserves as of December 31, 2016 and 57% of our average daily Boe production for the fourth quarter of 2016. Our average daily production from such properties was 118,773 Boe per day for the fourth quarter of 2016, a decrease of 20% from the comparable 2015 period due to natural declines in production, our planned reduction in drilling and completion activities, and persistent severe winter weather in North Dakota in late 2016. Our principal producing properties in the North region are located 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. We are a leading producer, leasehold owner and operator in the Bakken. As of December 31, 2016, we controlled one of the largest leasehold positions in the Bakken with approximately 1.4 million gross (848,500 net) acres under lease.
Our total Bakken production averaged 104,524 Boe per day for the fourth quarter of 2016, down 23% from the 2015 fourth quarter. For the year ended December 31, 2016, total Bakken production decreased 13% over 2015. We significantly reduced our drilling and well completion activities in the Bakken in 2016 in response to depressed crude oil prices, which reduced our production volumes. In 2016, we completed 192 gross (38 net) wells in the Bakken compared to 650 gross (181 net) wells completed in 2015. Our 2016 activity in the Bakken focused on limited development of de-risked, higher rate-of-return areas in core parts of North Dakota and the testing of various enhanced completion technologies to determine optimal methods for improving crude oil recoveries and rates of return. As a result of our reduced well completion activities, our inventory of uncompleted wells in North Dakota increased from 135 gross (107 net) operated wells at year-end 2015 to 187 gross (138 net) operated wells at December 31, 2016.
Our Bakken properties represented 46% of our total proved reserves at December 31, 2016 and 50% of our average daily Boe production for the 2016 fourth quarter. Our total proved Bakken field reserves as of December 31, 2016 were 592 MMBoe, which represents a decrease of 11% compared to December 31, 2015 due to reservoir production, reduced drilling, and downward reserve revisions in 2016 prompted by lower commodity prices and changes in drilling plans. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,081 gross (600 net) wells as of December 31, 2016.
In response to the stabilization and improvement in commodity prices in late 2016 we plan to increase our activities in North Dakota Bakken in 2017 relative to 2016 and begin working down our large inventory of uncompleted wells. In 2017, we plan to invest approximately $1.04 billion to drill, complete and initiate production on 351 gross (143 net) operated and non-

13



operated wells in North Dakota Bakken. This includes $550 million for the completion and initiation of production on certain non-operated Bakken wells and 131 gross (100 net) operated Bakken wells that were drilled but not completed as of year-end 2016, $226 million toward the drilling of 101 gross (57 net) new operated Bakken wells, of which 17 gross (8 net) wells are expected to have first production in 2017, and $264 million on new non-operated Bakken drilling.
We plan to maintain our current level of four operated rigs in North Dakota Bakken throughout 2017. Additionally, we plan to use, on average, seven well completion crews in North Dakota Bakken throughout 2017, up from four completion crews at December 31, 2016. Our 2017 drilling and completion activities will focus on core parts of North Dakota Bakken that provide opportunities to work down our inventory of uncompleted wells, convert undeveloped acreage to acreage held by production, increase capital efficiency, reduce finding and development costs, and improve rates of return.
Red River Units
The Red River units are comprised of nine units located along the Cedar Creek Anticline in North Dakota, South Dakota and Montana that produce crude oil and natural gas from the Red River “B” formation. Our principal producing properties in the Red River units include the Cedar Hills units in North Dakota and Montana, the Medicine Pole Hills units in North Dakota, and the Buffalo Red River units in South Dakota. Our properties in the Red River units comprise a portion of the Cedar Hills field.
All combined, our Red River units and adjacent areas represented 3% of our total proved reserves as of December 31, 2016 and 5% of our average daily Boe production for the fourth quarter of 2016. Our average daily production from these legacy properties decreased 13% in the fourth quarter of 2016 compared to the fourth quarter of 2015 due to natural declines in production and reduced drilling activity. We had limited activity in the Red River units in 2016, choosing instead to allocate capital to areas in North Dakota Bakken and Oklahoma that generate more attractive rates of return. For 2017, we plan to invest approximately $26 million in the Red River units primarily on well workover activities aimed at enhancing production and recoveries for these legacy properties.
South Region
Our properties in the South region represented 50% of our total proved reserves as of December 31, 2016 and 43% of our average daily Boe production for the fourth quarter of 2016. For the 2016 fourth quarter, our average daily production from such properties was 91,088 Boe per day, an increase of 20% from the comparable period in 2015. Our principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.
Historically, our properties in Blaine, Dewey and Custer counties of Oklahoma that produced from the Woodford formation were referred to as the Northwest Cana district, while properties often underlying the same surface acreage in those counties that produced from the Meramec and Osage formations were referred to as the STACK district. Such properties were historically combined by us and referred to as "Northwest Cana/STACK". Effective December 31, 2016, we now refer to such properties simply as "STACK".
SCOOP
The SCOOP play currently extends across Garvin, Grady, Stephens, Carter, McClain and Love counties in Oklahoma and contains crude oil and condensate-rich fairways as delineated by numerous industry wells. We are a leading producer, leasehold owner and operator in the SCOOP play. As of December 31, 2016, we controlled one of the largest leasehold positions in SCOOP with approximately 617,700 gross (345,700 net) acres under lease.
Our SCOOP leasehold has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation in Oklahoma. In recent years, our drilling activities have resulted in the vertical expansion of our SCOOP Woodford position and discovery of the SCOOP Springer formation, which is located approximately 1,000 to 1,500 feet above the Woodford formation. Located in the heart of our SCOOP acreage, our Springer position supplements our Woodford leasehold and expands our resource potential and inventory in the play. 
Our 2016 drilling activity in SCOOP focused on continued development of de-risked, higher rate-of-return areas in core parts of the play. Additionally, in 2016 we continued to improve upon our enhanced completion designs by testing various combinations of fluid types, proppant types and volumes, and stimulation stage lengths to determine optimal methods for improving recoveries and rates of return. Notably, in 2016 we completed our first enhanced completion density test in the SCOOP Woodford oil window at the seven-well May unit. Enhanced completion designs utilized at the May unit resulted in initial production rates that outperformed offsetting wells. Results from the test were encouraging for the future development of our SCOOP Woodford properties.

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SCOOP represented 37% of our total proved reserves as of December 31, 2016 and 30% of our average daily Boe production for the fourth quarter of 2016. Production in SCOOP decreased to an average rate of 63,490 Boe per day during the fourth quarter of 2016, down 2% compared to the 2015 fourth quarter. For the year ended December 31, 2016, SCOOP production grew 6% over 2015. We completed 72 gross (28 net) wells in SCOOP during 2016. Proved reserves increased 14% year-over-year to 472 MMBoe as of December 31, 2016, of which 32% represents proved developed reserves. Our inventory of proved undeveloped drilling locations in SCOOP as of December 31, 2016 totaled 370 gross (250 net) wells.
In 2017, we plan to invest approximately $245 million to drill, complete and initiate production on 108 gross (24 net) operated and non-operated wells in the SCOOP play. We plan to average approximately five operated rigs and one completion crew in SCOOP throughout 2017, consistent with our current activity levels. Our 2017 drilling program will continue to focus on expanding the known productive extents of the SCOOP Woodford and SCOOP Springer formations and de-risking our acreage, while focusing on areas that provide opportunities for converting undeveloped acreage to acreage held by production, increasing capital efficiency, reducing finding and development costs, and maximizing rates of return.
STACK
STACK, an acronym for Sooner Trend Anadarko Canadian Kingfisher, is a significant new resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. As of December 31, 2016, we controlled one of the largest leasehold positions in STACK with approximately 353,800 gross (196,200 net) acres under lease. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma where we believe the reservoirs are typically thicker and deliver superior production rates relative to normal-pressured areas of the STACK petroleum system.
We completed our first STACK well in mid-2015. Building on early success achieved from our initial 2015 drilling activities, we significantly increased our leasing and drilling activities in the STACK in 2016. Our 2016 activities focused on expanding our understanding of the productive extents and hydrocarbon content of the play both vertically and horizontally and working to establish optimum well spacing and enhanced completion methods for future field development.
To help accelerate our understanding of the resource potential of STACK, in 2016 we drilled our first density pilot in the over-pressured oil window of the play at our eight-well Ludwig unit. Results from the Ludwig unit were very encouraging and demonstrated consistency of production and the significant potential value of our leasehold in STACK. The Ludwig results helped to de-risk a portion of our acreage and provided validation to increase our development activities in the play.
Since the completion of our first STACK well in mid-2015 we have successfully tested productive zones in the play, applied enhanced completions to improve recoveries, demonstrated repeatability of results, reduced drilling times, reduced well costs, and de-risked a sizeable portion of our acreage in the play. Due to the success of these efforts, STACK has become another significant growth platform for us and is expected to be an important contributor to our long-term growth. To facilitate the future development of our STACK acreage, we are in the process of increasing our water recycling and distribution capabilities in the play. Additionally, we are increasing our gathering and takeaway capabilities to handle crude oil and natural gas production expected from development of the play.
Our STACK properties represented 13% of our total proved reserves as of December 31, 2016 and 12% of our average daily Boe production for the fourth quarter of 2016. Production in STACK increased to an average rate of 24,426 Boe per day during the fourth quarter of 2016, up 217% over the 2015 fourth quarter due to additional drilling and completion activity resulting from our drilling program. For the year ended December 31, 2016, STACK production grew 206% over 2015. We completed a total of 97 gross (26 net) wells in STACK during 2016. Proved reserves totaled 161 MMBoe as of December 31, 2016, of which 28% represents proved developed reserves. Our inventory of proved undeveloped drilling locations stood at 264 gross (113 net) wells as of December 31, 2016.
In 2017, we plan to invest approximately $435 million to drill, complete and initiate production on 157 gross (51 net) operated and non-operated wells in STACK. We plan to average approximately 11 operated rigs in STACK throughout 2017, consistent with our current activity level. Additionally, we plan to use, on average, three completion crews in STACK throughout 2017, up from two crews in 2016. Our 2017 activities will focus on delineating and de-risking our acreage, expanding the known productive extents of the play through the completion of new density test projects, monitoring production from enhanced completions, and continued refinement of our geologic and economic models in the area.

15



Production and Price History
The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2016, 2015 and 2014 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2016 (North Dakota Bakken and SCOOP). Information for the STACK field is also presented.  
 
 
Year ended December 31,
 
 
2016
 
2015
 
2014
Net production volumes:
 
 
 
 
 
 
Crude oil (MBbls)
 
 
 
 
 
 
North Dakota Bakken
 
31,723

 
37,539

 
30,917

SCOOP
 
6,807

 
7,198

 
3,652

STACK
 
1,552

 
245

 
146

Total Company
 
46,850

 
53,517

 
44,530

Natural gas (MMcf)
 
 
 
 
 
 
North Dakota Bakken
 
50,532

 
47,425

 
33,610

SCOOP
 
102,032

 
91,687

 
55,017

STACK
 
27,983

 
10,704

 
9,868

Total Company
 
195,240

 
164,454

 
114,295

Crude oil equivalents (MBoe)
 
 
 
 
 
 
North Dakota Bakken
 
40,145

 
45,444

 
36,518

SCOOP
 
23,813

 
22,479

 
12,822

STACK
 
6,216

 
2,029

 
1,791

Total Company
 
79,390

 
80,926

 
63,579

Average sales prices: (1)
 
 
 
 
 
 
Crude oil ($/Bbl)
 
 
 
 
 
 
North Dakota Bakken
 
$
34.33

 
$
39.76

 
$
80.22

SCOOP
 
38.87

 
43.98

 
87.58

STACK
 
41.95

 
41.23

 
89.60

Total Company
 
35.51

 
40.50

 
81.26

Natural gas ($/Mcf)
 
 
 
 
 
 
North Dakota Bakken
 
$
1.05

 
$
2.34

 
$
6.63

SCOOP
 
2.24

 
2.39

 
5.23

STACK
 
1.87

 
2.06

 
4.29

Total Company
 
1.87

 
2.31

 
5.40

Crude oil equivalents ($/Boe)
 
 
 
 
 
 
North Dakota Bakken
 
$
28.45

 
$
35.29

 
$
73.96

SCOOP
 
20.71

 
23.81

 
47.35

STACK
 
18.88

 
15.87

 
30.92

Total Company
 
25.55

 
31.48

 
66.53

Average costs per Boe: (1)
 
 
 
 
 
 
Production expenses ($/Boe)
 
 
 
 
 
 
North Dakota Bakken
 
$
4.59

 
$
4.79

 
$
5.67

SCOOP
 
1.13

 
1.10

 
1.13

STACK
 
1.00

 
3.52

 
4.97

Total Company
 
3.65

 
4.30

 
5.58

Production taxes and other expenses ($/Boe)
 
$
1.79

 
$
2.47

 
$
5.54

General and administrative expenses ($/Boe)
 
$
2.14

 
$
2.34

 
$
2.92

DD&A expense ($/Boe)
 
$
21.54

 
$
21.57

 
$
21.51


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(1)
Average sales prices and per unit costs have been calculated using sales volumes and exclude any effect of derivative transactions.
The following table sets forth information regarding our average daily production by region for the fourth quarter of 2016: 
 
 
Fourth Quarter 2016 Daily Production
 
 
Crude Oil
(Bbls per day)
 
Natural Gas
(Mcf per day)
 
Total
(Boe per day)
North Region:
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
North Dakota Bakken
 
75,200

 
125,011

 
96,035

Montana Bakken
 
6,858

 
9,786

 
8,489

Red River units
 
 
 
 
 
 
Cedar Hills
 
7,369

 
1,222

 
7,572

Other Red River units
 
2,094

 
2,842

 
2,568

Other
 
460

 
21,893

 
4,109

South Region:
 
 
 
 
 
 
SCOOP
 
17,353

 
276,820

 
63,490

STACK
 
6,804

 
105,733

 
24,426

Arkoma Woodford
 
3

 
11,559

 
1,929

Other
 
345

 
5,385

 
1,243

Total
 
116,486

 
560,251

 
209,861

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, 2016. One or more completions in the same well bore are counted as one well.
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total Wells
 
 
Gross    
 
Net    
 
Gross    
 
Net    
 
Gross    
 
Net    
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
3,786

 
1,187

 

 

 
3,786

 
1,187

Montana Bakken
 
406

 
265

 

 

 
406

 
265

Red River units
 
 
 
 
 
 
 
 
 
 
 


Cedar Hills
 
136

 
130

 

 

 
136

 
130

Other Red River units
 
131

 
117

 

 

 
131

 
117

Other
 
8

 
4

 
18

 
4

 
26

 
8

South Region:
 
 
 
 
 
 
 
 
 
 
 

SCOOP
 
219

 
138

 
332

 
106

 
551

 
244

STACK
 
60

 
23

 
214

 
71

 
274

 
94

Arkoma Woodford
 
1

 

 
385

 
54

 
386

 
54

Other
 
157

 
123

 
178

 
84

 
335

 
207

Total
 
4,904

 
1,987

 
1,127

 
319

 
6,031

 
2,306

Title to Properties
As is customary in the crude oil and natural gas industry, upon initiation of acquiring oil and gas leases covering fee mineral interests on undeveloped lands which do not have associated proved reserves, contract landmen conduct a title examination of courthouse records to determine fee mineral ownership. Such title examinations, lease form, and final terms are reviewed and approved by Company landmen prior to consummation.

17



For acquisitions from third parties, whether lands are producing crude oil and natural gas or non-producing, Company and contract landmen perform title examinations at applicable courthouses, obtain a physical well site inspection, and examine the seller's internal land, legal, operational, environmental, well, marketing and accounting records upon execution of a mutually acceptable purchase and sale agreement. We may also procure an acquisition title opinion from outside legal counsel on higher value properties.
Prior to the commencement of drilling operations, we procure an original title opinion, or supplement an existing title opinion, from outside legal counsel and perform curative work to satisfy requirements pertaining to material title defects, if any. We will not commence drilling operations until we have cured material title defects pertaining to the Company's interest.
We have procured title opinions and cured material defects as to Company interests 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 leasehold 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 either crude oil refining companies or midstream marketing companies at major market centers. Other production not sold at major market centers is sold at the lease. In the Bakken and SCOOP areas we have significant production directly connected to pipeline gathering systems, with the remaining balance of production primarily being transported by truck. Additionally in the Bakken, a portion of our production is sold onto rail delivery systems. Where directly marketed crude oil is transported by truck, it is delivered to a point on a pipeline system for further delivery, or is delivered directly to a refinery. Where crude oil is sold at the lease the sale is complete at that point.
The majority of our natural gas production is sold at our lease locations to midstream purchasers under term contracts. These contracts include multi-year term agreements, many with acreage dedication. Some of our contracts allow us the flexibility to accept, as partial payment for our sale of gas in the field, an “in-kind” volume of processed gas at the tailgate of the midstream purchaser’s processing plant. When we elect to do so, we transport this processed gas to a downstream market where it is sold. Sales at these downstream markets are mostly under monthly interruptible packaged volume deals, short term seasonal packages, and long term multi-year contracts. We continue to develop relationships and have the potential to enter into additional contracts with end-use customers, including utilities, industrial users, and liquefied natural gas exporters, for sale of gas we elect to take in-kind in lieu of cash for our leasehold sales.
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, processing and refining facilities, most of which are owned by third parties, and on the availability of rail transportation.
For the year ended December 31, 2016, sales to Phillips 66 Company accounted for approximately 18% of our total crude oil and natural gas revenues. No other purchasers accounted for more than 10% of our total crude oil and natural gas revenues for 2016. We believe the loss of any single purchaser would not have a material adverse effect on our operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.
Competition
We operate in a highly competitive environment for acquiring properties, marketing crude oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. 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 economically in a highly competitive environment. In addition, as a result of the significant decrease in commodity prices in recent years, the number of providers of materials and services has decreased in the regions where we operate. As a result, the likelihood of experiencing competition and shortages of materials and services may be further increased in connection with any period of commodity price recovery.

18



Regulation of the Crude Oil and Natural Gas Industry
Our operations are conducted onshore almost entirely in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and interpretations affecting our industry have been and are pervasive with the imposition of new or increased requirements on us and other industry participants. These laws, regulations and other requirements often carry substantial penalties for failure to comply and may have a significant effect on the exploration, development, production or sale of crude oil and natural gas and increase the cost of doing business and affect profitability. In addition, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations. We do not expect any future legislative or regulatory initiatives will affect us in a manner materially different than they would affect our similarly situated competitors.
The following is a discussion of significant laws, rules 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 ("NGLs") 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. Since the 1970s, the United States has regulated the exportation of petroleum and petroleum products, which restricted the markets for these commodities and affected sales prices. However, in December 2015 the U.S. Congress passed a legislative bill eliminating the export restrictions beginning in January 2016.
With regard to our physical sales of crude oil and any derivative instruments relating to crude oil, we are required to comply with anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”). See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FTC and CFTC Market Manipulation Rules.” If 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. As the interstate and intrastate transportation rates we pay are generally applicable to all comparable shippers, we believe the regulation of intrastate transportation rates will not affect us in a way that materially differs from the effect on our similarly situated competitors.
Further, interstate pipelines and intrastate common carrier pipelines must provide service on an equitable basis and 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 we are subject to proration provisions, which are severally described in the pipelines’ published tariffs. We believe we generally will have access to crude oil pipeline transportation services to the same extent as our similarly situated competitors.
We transport operated crude oil production from our North region to market centers using primarily a combination of rail and pipeline transportation facilities owned and operated by third parties. Approximately 8% of such production was shipped by rail in December 2016, with the remainder being shipped primarily by pipeline. The U.S. Department of Transportation’s (“U.S. DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relating to transportation of crude oil by rail and pipeline. 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”), the Occupational Safety and Health Administration, and other federal regulatory agencies. Additionally, various state and local agencies have jurisdiction over disposal of hazardous waste and regulate movement of hazardous materials if not preempted by federal law.
In 2008, the U.S. Congress passed the Rail Safety and Improvement Act, which implemented regulations governing different areas related to railroad safety. Subsequently, the FRA and PHMSA have taken several actions related to the transport of crude

19



oil, including but not limited to: issuing an order requiring testing, classification and handling of crude oil as a hazardous material; requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas; issuing safety advisories, alerts, emergency orders and regulatory updates; conducting special unannounced inspections; moving forward with rulemaking to enhance tank car standards for certain trains carrying crude oil and ethanol; and reaching agreement with the railroad industry on a series of voluntary actions it can take to improve safety. Notably, in May 2014 the U.S. DOT issued an order requiring all railroads operating trains containing large amounts of Bakken crude oil to notify state emergency response commissions about the operation of such trains through their states. The order requires each railroad operating trains containing more than 1,000,000 gallons of Bakken crude oil, or approximately 35 tank cars, in a particular state to provide the state with notification regarding the volumes of Bakken crude oil being transported, frequencies of anticipated train traffic and the route through which Bakken crude oil will be transported.  Also in May 2014, the FRA and PHMSA issued a safety advisory to the rail industry strongly recommending the use of tank cars with the highest level of integrity in their fleet when transporting Bakken crude oil. In May 2015, PHMSA issued a final rule which requires, among other things, enhanced tank car standards for new and existing tank cars, a classification and testing program for crude oil, and a requirement that older DOT-111 tank cars be retrofitted to comply with new tank car design standards in accordance with a specified timeline beginning in May 2017. More recently, in August 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids between 2018 and 2029. Separately, in July 2016, PHMSA proposed a new rule that would expand the applicability of comprehensive oil spill response plans so that any railroad that transports a single train carrying 20 or more loaded tank cars of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train must have a current, comprehensive, written plan.
We do not own or operate rail transportation facilities or rail cars; however, regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at market centers throughout the United States, which could have a material adverse effect on our financial condition, results of operations and cash flows. We are unable to estimate the potential impact on our business associated with new federal or state rail transportation regulations; however, at this time we do not expect such regulations will have a material impact on us nor will they affect us in a materially different way than similarly situated competitors.
With respect to transportation of crude oil by pipelines, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act ("PIPES Act") was signed into law, which strengthens PHMSA's safety authority and includes provisions on advancing the safe transportation of energy commodities and other hazardous materials. The PIPES Act includes provisions aimed at increasing inspection requirements for certain underwater crude oil pipelines; improving protection of coastal areas by designating them as environmentally sensitive to pipeline failures; setting minimum safety standards for underground natural gas storage facilities, and promoting better use of data and technology to prevent damage and improve safety of pipeline systems, among other things. We are unable to estimate the potential impact on our business associated with the PIPES Act regulations; however, we do not expect such regulations will affect us in a materially different way than similarly situated competitors.
Pipeline regulation at the state level continues as well. For example, in December 2014 the North Dakota Industrial Commission ("NDIC") introduced rules designed to reduce the potential flammability of crude oil produced from the Bakken petroleum system (the Bakken, Three Forks, and Sanish Pool formations) before it is loaded on railcars and transported. The rules, which became effective in April 2015, outline a series of standards for pressure and temperature for production facilities to follow in order to separate certain liquids and gases from the crude oil prior to transport. While these rules could increase the cost of doing business in North Dakota, we do not expect the rules will have a material impact on us nor will they affect us in a way that materially differs from our similarly situated competitors.
Regulation of sales and transportation of natural gas
In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. The FERC, which has the authority under the Natural Gas Act (“NGA”) to regulate prices, terms, and conditions for the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. However, either the U.S. Congress or the FERC (with respect to the resale of gas in interstate commerce) could re-impose price controls in the future. The U.S. Department of Energy (“U.S. DOE”) regulates the terms and conditions for the exportation and importation of natural gas (including liquefied natural gas or “LNG”). U.S. law provides for very limited regulation of exports to and imports from any country that has entered into a Free Trade Agreement (“FTA”) with the United States providing for national treatment of trade in natural gas; however, the U.S. DOE’s regulation of imports and exports from and to countries without an FTA 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.

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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 open access policies are necessary to improve the competitive structure of the natural gas pipeline industry and to create a regulatory framework to put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the 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 the pro-competitive regulatory approach established by the FERC will continue. However, we do not believe any action taken by FERC will affect us in a materially different way than similarly situated 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.” If we violate the anti-market manipulation laws and regulations, we could be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to various FERC orders, we may be required to submit reports to the FERC for some of our operations. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency and Reporting Rules.”
Gathering service, which occurs upstream of jurisdictional transmission services, is generally regulated by the states. 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 moving natural gas to point of sale locations. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, equitable take requirements. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels in the future. We cannot predict what effect, if any, such changes may have on us, but the natural gas industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes, including changes in the interpretation of existing requirements or programs to implement those requirements. We do not believe we would be affected by any such regulatory changes in a materially different way than our similarly situated competitors.
Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Such regulation within a particular state will generally affect all intrastate natural gas shippers on a comparable basis, we believe the regulation of intrastate natural gas transportation in states in which we operate and ship natural gas on an intrastate basis will not affect us in a way that materially differs from our similarly situated competitors.
Regulation of production
The production of crude oil and natural gas is regulated by 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. Each 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, the plugging and abandonment of wells, and limitations or prohibitions on the venting or flaring of natural gas. These regulations limit the amount of crude oil and natural gas we can produce from our wells and the number of wells and locations we can drill. Although we can and do apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production, severance or excise tax on the production and sale of crude oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our similarly situated competitors are generally subject to the same statutes, regulatory requirements and restrictions.

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Other federal laws and regulations affecting our industry
Dodd-Frank Wall Street Reform and Consumer Protection Act. In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules and regulations to implement the new legislation. Although the CFTC has issued final regulations to implement significant aspects of the legislation, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.
In November 2013 and December 2016, the CFTC proposed rules establishing position limits with respect to certain futures and option contracts and equivalent swaps, subject to exceptions for certain bona fide hedging. As these new position limit rules are not yet final, the impact of these provisions on us is uncertain at this time.
Pursuant to the Dodd-Frank Act, absent an exception, mandatory clearing is now required for all market participants. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet required the clearing of any other classes of swaps, including physical commodity swaps, and the trade execution requirement does not apply to swaps not subject to a clearing mandate. Although we expect to qualify for the end-user exception from the clearing requirement for our swaps entered into to hedge our commercial risks, the application of the mandatory clearing requirements to other market participants, such as swap dealers, along with changes to the markets for swaps as a result of the trade execution requirement, may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract market or swap execution facility. The ultimate effect of the proposed rules and any additional regulations on our business is uncertain.
In December 2015, the CFTC issued final rules establishing minimum margin requirements for uncleared swaps for swap dealers and major swap participants. The final rules do not impose margin requirements on commercial end users. Although we expect to qualify for the end-user exception from the margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce our liquidity and cash available for capital expenditures and could reduce our ability to manage commodity price volatility and the volatility in our cash flows.
In addition to the CFTC’s swap regulations, certain foreign jurisdictions are in the process of adopting or implementing laws and regulations relating to transactions in derivatives, including margin and central clearing requirements, which in each case may affect our counterparties and the derivatives markets generally. Other rules, including the restrictions on proprietary trading adopted under Section 619 of the Dodd-Frank Act, also known as the Volcker Rule, may alter the business practices of some of our counterparties and in some cases may cause them to stop transacting in or making markets in derivatives. Moreover, federal banking regulators are reevaluating the authorization under which banking entities subject to their authority may engage in physical commodities transactions.
Although we cannot predict the ultimate outcome of these rulemakings, they could 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 could have an adverse effect on our ability to hedge risks associated with our business.
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. For example, EPAct 2005 amended the NGA to add an anti-market manipulation provision making it unlawful for any entity 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 natural gas pipelines and storage companies which 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 described further below. The EPAct 2005 also 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 and disgorgement of profits associated with any violation.
FERC Market Transparency and Reporting Rules. The FERC requires wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year 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

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contribute to the formation of price indices. The FERC also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. Failure to comply with these reporting requirements could subject us to enhanced civil penalty liability under the EPAct 2005.
FTC and CFTC Market Manipulation Rules. Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the FTC. Under the EISA, the FTC issued its Petroleum Market Manipulation Rule (the “Rule”), which became effective in November 2009. The Rule 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. Under the EISA, the FTC has authority to request a court to impose fines of up to $1,000,000 per day per violation. The CFTC has also adopted anti-market manipulation regulations that prohibit, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC may assess fines of up to the greater of $1,000,000 or triple the monetary gain for violations of these anti-market manipulation regulations. Knowing or willful violations of the Commodity Exchange Act is also a felony.
Additional proposals and proceedings potentially affecting the crude oil and natural gas industry are pending before the U.S. Congress, the FERC and the courts. We cannot predict the ultimate impact these or the above laws and regulations may have on our crude oil and natural gas operations. We do not believe we will be affected in a materially different way than our similarly situated competitors.
Environmental regulation
General. We are subject to stringent and complex federal, state, and local laws, rules and regulations governing environmental compliance, including the discharge of materials into the environment. These laws, rules and regulations may, among other things:
require the acquisition of various permits to conduct exploration, drilling and production operations;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with crude oil and natural gas drilling, production and transportation activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals;
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and
impose substantial liabilities for pollution resulting from drilling and production operations.
These laws, rules 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 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. We strive to operate in accordance with all applicable regulatory and legal requirements and have focused on continuously improving our environmental performance; however, at times circumstances may arise that adversely affect our compliance with applicable environmental requirements. We have established internal policies, procedures and processes regarding environmental matters for all employees, contractors, and vendors. In connection with our environmental initiatives, we work to identify and manage our environmental risks and the impact of our operations and continually improve our environmental compliance. However, we cannot guarantee that our efforts will always be successful.
One of our environmental initiatives is the reduction of air emissions produced from our operations, particularly with respect to the flaring of natural gas from our operated well sites in the Bakken field of North Dakota. North Dakota statutes permit flaring of natural gas from a well that has not been connected to a gas gathering line for a period of one year from the date of a well's first production. After one year, a producer is required to cap the well, connect it to a gas gathering line, find acceptable alternative uses for a percentage of the flared gas, or apply to the NDIC for a written exemption for any future flaring; otherwise, the producer is required to pay royalties and production taxes based on the volume and value of the gas flared from the unconnected well. While the NDIC ultimately determines the volume and value of any such gas flared and the applicable royalties and production taxes, the NDIC has thus far generally accepted our methods for calculating these figures. Furthermore, the NDIC has generally accepted applications we have submitted to secure exemptions from the post-year flaring restrictions. Finally, NDIC rules for new drilling permit applications also require the submission of gas capture plans addressing measures taken by operators to capture and not flare produced gas, regardless of whether it has been or will be

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connected within the first year of production. Thus far, the NDIC has generally accepted our gas capture plans submitted with applications for drilling permits. The deadline to comply with the requirement to capture 85% of the natural gas produced from a field was November 1, 2016 and the target capture percentage increases to 90% beginning October 1, 2020. Compliance with the NDIC's flaring requirements or the imposition of any additional limitations on flaring could result in increased costs and have an adverse effect on our operations.
For the year ended December 31, 2016, we delivered approximately 91% of our operated natural gas production in the North Dakota Bakken field to market, flaring approximately 9% compared to 13% in 2015 and 13% in 2014. According to data published by the NDIC, our industry as a whole flared approximately 10% of produced natural gas volumes in the North Dakota Bakken field during 2016. We are a participant in the NDIC’s Flaring Reduction Task Force and are engaged in working with other task force members and the NDIC to develop action plans for mitigating natural gas flaring in the state. Flared natural gas volumes from our operated SCOOP and STACK properties in Oklahoma are negligible given the existence of established natural gas transportation infrastructure.
There are environmental and financial risks associated with natural gas flaring and we attempt to manage these risks on an ongoing basis. To date, we have taken numerous actions to reduce flaring from our operated well sites. We make efforts to coordinate our well completion operations to coincide with well connections to gathering systems in order to minimize flaring, but may not always be successful in these efforts. Our ultimate goal is to reduce natural gas flaring from our operated well sites as much as is practicable. For example, 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 in an effort to minimize impacts to the environment. Our levels of flaring are 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.
We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Although we believe our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you the passage of more stringent laws or regulations in the future will not materially impact our financial position, results of operations or cash flows.
Environmental laws, rules and regulations. Some of the existing environmental rules and regulations to which we are subject include, among others: (i) regulations by the Environmental Protection Agency (“EPA”) and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the 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 lease restoration activities to prevent future contamination from prior operations; (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, 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 a principal federal statute governing the treatment, storage and disposal of solid and hazardous wastes, and comparable state statutes; (viii) the Safe Drinking Water Act and analogous state laws which impose requirements relating to our underground injection activities; (ix) the National Environmental Policy Act and comparable state statutes, which require government agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment; (x) the Endangered Species Act and comparable state statutes, which afford protections to certain plant and animal species; (xi) the Migratory Bird Treaty Act, which imposes certain restrictions for the protection of migratory birds; (xii) the Bald and Golden Eagle Protection Act, which imposes certain restrictions for the protection of bald and golden eagles; (xiii) the Emergency Planning and Community Right to Know Act and comparable state statutes, which require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations, and (xiv) state regulations and statutes governing the handling, treatment, storage and disposal of technologically enhanced naturally occurring radioactive material. Failure to comply with these laws, rules and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the issuance of orders enjoining performance of some or all of our operations, and potential litigation.
Air emissions and climate change. Federal, state and local laws and regulations have been and may be enacted to address concerns about the effects the emission of carbon dioxide, methane and other identified “greenhouse gases” may have on the environment and climate worldwide, generally referred to as “climate change.” For example, in October 2015 the EPA revised the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary

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and secondary standards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. The EPA has also adopted regulations under existing provisions of the federal Clean Air Act establishing, among other things, Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources. Moreover, EPA’s source determination rule, which was finalized in June 2016, specifies that oil and gas production facilities are considered to be “adjacent” (and therefore aggregated for air permitting purposes) if they are on the same site or on sites that share equipment and are within ¼ mile of each other. This rule increases the potential for individual well facilities to be viewed collectively by EPA as a single, large stationary source and, therefore, subject to PSD and/or Title V. Although we currently do not have any facilities required to adhere to PSD or Title V permit requirements, a change in our operational approachin light of EPA’s source determination rulecould trigger Title V and/or PSD requirements for a multi-well pad facility with substantial production or centralized production facilities. EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
In addition, the EPA has adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. New Source Performance Standard (“NSPS”) Subpart OOOO (“Quad O”), which was first promulgated in 2012, requires, among other things, the reduction of volatile organic compound (“VOC”) emissions from three subcategories of fractured and refractured oil and gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured oil and gas wells. All three subcategories of wells must route flowback emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” fractured and refractured wells must use reduced emission completions or “green completions.” The rule also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The rule is designed to limit emissions of VOCs, sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oil and natural gas production facilities, and natural gas transmission compressor stations. We have modified our operations and well equipment as needed to comply with these rules. Ongoing compliance with the rules is not expected to affect us in a way materially different from our similarly situated competitors.
In addition, in June 2016, the EPA finalized new regulations (NSPS Subpart OOOOa, commonly referred to as “Quad Oa”) setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities in an effort to reduce methane emissions from the oil and gas sector by up to 45% from 2012 levels by 2025 even though there was consensus at the time that oil and gas producers’ compliance with Quad O had already achieved reductions in methane emissions.
In addition, in November 2016 EPA issued an industry wide Information Collection Request (“ICR”) pursuant to Section 114 of the Clean Air Act seeking information to help the agency determine how best to reduce methane and other emissions from existing sources in the oil and gas industry. This action is typically viewed as a precursor to a future new regulation which, if promulgated, would have the potential to impact our operating costs for existing facilities. Unlike Quad Oa, which only applies to wells constructed, reconstructed or modified after September 18, 2015, any such new ICR-related EPA regulation could target emissions from existing sources of oil and gas; however, future action by EPA with respect to methane emissions from existing oil and gas sources is uncertain at this time.
Additional regulation with respect to methane emissions occurred in November 2016, when the U.S. Department of Interior's Bureau of Land Management ("BLM") published a final rule commonly referred to as the “BLM venting and flaring rule.” Similar to Quad Oa, the BLM venting and flaring rule imposes requirements related to methane emissions from crude oil and natural gas sources. However, the U.S. Congress has introduced a resolution seeking to repeal the BLM methane rule under the Congressional Review Act and future implementation of the BLM methane rule is uncertain. To the extent new methane emission regulationswhether it is the BLM venting and flaring rule or a prospective EPA rule targeting methane emissions from existing sourcesimpose reporting obligations on, or limit emissions of greenhouse gases from, our equipment and operations they could require us to incur costs to reduce emissions associated with our operations, but the impact of these measures is not expected to be material and will not affect us in a materially different way from our similarly situated competitors.
At an international level, in December 2015, a global climate agreement was reached in Paris at the 21st Conference of Parties organized by the United Nations under the Framework Convention on Climate Change. The agreement, which goes into effect in 2020, resulted in nearly 200 countries, including the United States, committing to work towards limiting global warming and agreeing to a monitoring and review process of greenhouse gas emissions. The agreement includes binding and non-binding elements and did not require ratification by the U.S. Congress. Nonetheless, the agreement may result in increased political

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pressure on the United States to ensure continued compliance with enforcement measures under the Clean Air Act and may spur further initiatives aimed at reducing greenhouse gas emissions in the future.
While the U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal legislation, a number of state and regional efforts have emerged aimed at tracking and reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. There has also been discussion of imposing a federal carbon tax on all fossil fuel production. Although it is not possible at this time to predict how such legislation or new regulations adopted to address greenhouse gas emissions will impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the crude oil and natural gas we produce. Finally, some scientists have concluded increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes having significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects from such causes were to occur, they could have an adverse effect on our exploration and production operations.
Both the EPA and the state of North Dakota pursued enforcement actions in 2016 against operators related to emissions generally and alleged noncompliance with the requirements of Quad O, Quad Oa, and relevant state regulations more specifically. One such enforcement action by EPA against an operator resulted in a consent decree between the parties that, if finalized by the federal district court in North Dakota, will require the operator to incur costs associated with a civil penalty, emissions-related mitigation projects, and implementation of a robust leak detection and repair program applicable to all of the operator’s wells in North Dakota. Similarly, the North Dakota Department of Health (“NDDH”), the department which administers state and federal environmental laws and regulations in North Dakota, sought in 2016 to have all operators in North Dakota voluntarily sign a “global consent decree” to resolve certain NDDH allegations that historic emissions by such operators constituted violations of state and federal laws and regulations. We did not sign the proposed NDDH global consent decree and it is not clear whether NDDH will continue to pursue the global consent decree in 2017. Finally, the U.S. Department of Justice (“DOJ”) announced in 2016 it had partnered with the Occupational Safety and Health Administration to pursue a “Worker Endangerment Initiative” seeking to promote worker safety by pursuing not only worker safety claims in connection with worker safety incidents but also environmental claims. DOJ believes criminal penalties in the worker safety laws are inadequate, so it has begun citing companies for violations of the endangerment provisions of the three major environmental statutes, the Clean Air Act, the Clean Water Act and the Resource Conservation and Recovery Act, in connection with its prosecution of companies for workplace safety incidents. In worker safety incidents at oil and gas production facilities, DOJ has threatened to allege emissions or other environmental-related claims caused or contributed to the worker safety incident.
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. In recent years there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and to induce seismic events. As a result, several federal and state agencies are studying the environmental risks with respect to hydraulic fracturing, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 related to such activities. In May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. In June 2016 EPA finalized a regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities. It has not been our practice to discharge wastewater to publicly owned treatment works, so the impact of this new regulation on us is not expected to be material.
Finally, in December 2016 EPA published a final study of the potential impacts of hydraulic fracturing activities on water resources. In its final report, the EPA indicated it found evidence hydraulic fracturing activities can impact drinking water resources under some circumstances. The report identified certain conditions where impacts from hydraulic fracturing activities can potentially be more frequent or severe. These include water withdrawals for hydraulic fracturing in times or areas of low water availability; spills during the handling of hydraulic fracturing fluids, chemicals or produced water resulting in large volumes or high concentrations of chemicals reaching groundwater resources; injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity thereby allowing gases or liquids to move to groundwater resources; injection of

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hydraulic fracturing fluids directly into groundwater resources; discharge of inadequately treated hydraulic fracturing wastewater to surface water, and disposal or storage of hydraulic fracturing wastewater in unlined pits thereby resulting in contamination of groundwater resources. In its final report, the EPA indicated it was not able to calculate or estimate the national frequency of impacts on drinking water resources from hydraulic fracturing activities or fully characterize the severity of impacts. Nonetheless, the results of the EPA's study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.
In March 2015, the BLM issued final rules related to the regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. Several parties challenged the regulations and the U.S. District Court of Wyoming temporarily stayed implementation of the regulations. In June 2016, the U.S. District Court of Wyoming ruled the BLM lacked the statutory authority to promulgate the regulations. The U.S. Department of Interior appealed the decision and the timing of resolution is uncertain. As of December 31, 2016, we held approximately 72,900 net undeveloped acres on federal land, representing approximately 9% of our total net undeveloped acres.
At the state level, several states, including states in which we operate, have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating or prohibiting the time, place and manner of drilling activities or hydraulic fracturing activities. In certain areas of the United States, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards.
Regulators in some states, including states in which we operate, are considering additional requirements related to seismicity and its potential association with hydraulic fracturing. For example, the Oklahoma Corporation Commission (the “OCC”) recently promulgated guidance for operators of crude oil and gas wells in certain seismically-active areas of the SCOOP and STACK plays in Oklahoma. This guidance provides for seismic monitoring by the OCC and for operators to temporarily suspend operations (for six hours or in limited circumstances, a longer period of time) when the OCC has been notified of then concurrent seismic events within a 1.25-mile radius of their operations of a magnitude exceeding 2.5 on the Richter scale. If seismic events exceeding this threshold were to occur near our active stimulation operations on a frequent basis, they could have an adverse effect on our operations.
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. The additives used in the hydraulic fracturing process on all wells we operate are disclosed on that website.
The adoption of any future federal, state or local laws, rules or implementing regulations imposing permitting or reporting obligations on, or otherwise limiting, hydraulic fracturing processes in areas in which we operate could make it more difficult and expensive to complete crude oil and natural gas wells in low-permeability formations, increase our costs of compliance and doing business, and delay, prevent or prohibit the development of natural resources from unconventional formations. Compliance, or the consequences of our failure to comply, could have a material adverse effect on our financial condition and results of operations. At this time it is not possible to estimate the potential impact on our business if such federal or state legislation is enacted into law.
Waste water disposal. Underground injection wells are a predominant method for disposing of waste water from oil and gas activities. In response to recent seismic events near underground injection wells used for the disposal of oil and gas-related waste waters, federal and some state agencies are investigating whether such wells have caused increased seismic activity. Some states, including states in which we operate, have delayed permit approvals, mandated a reduction in injection volumes, or have shut down or imposed moratoria on the use of injection wells. Regulators in some states, including states in which we operate, are considering additional requirements related to seismicity. For example, the Oklahoma Corporation Commission (“OCC”) has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of Oklahoma. These rules require, among other things, that disposal well operators conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma has adopted a “traffic light” system, wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. At the federal level, the EPA's current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. We cannot predict the EPA's future actions in this regard. The introduction of new environmental initiatives and regulations related to the disposal of wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize underground injection wells. A lack of waste water disposal sites could cause us to delay, curtail or discontinue our exploration and development plans. Additionally, increased costs associated with the transportation and

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disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. These costs are commonly incurred by all oil and gas producers and we do not believe the costs associated with the disposal of produced water will have a material adverse effect on our operations to any greater degree than other similarly situated competitors. In 2015, we began operation of water recycling facilities in the SCOOP area that economically reuse stimulation water for both operational efficiencies and environmental benefits.

Employee Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, as amended, and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local governmental authorities and citizens.
Employees
As of December 31, 2016, we employed 1,080 people. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. We utilize the services of independent contractors to perform various field and other services.
Company Contact Information
Our corporate internet website is www.clr.com. Through the investor relations section of our website, we make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after the report is filed with or furnished to the SEC. For a current version of various corporate governance documents, including our Code of Business Conduct and Ethics and the charters for various committees of our Board of Directors, please see our website. We intend to disclose amendments to, or waivers from, our Code of Business Conduct and Ethics by posting to our website. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.
We intend to use our website as a means of disclosing material information and for complying with our disclosure obligations under SEC Regulation FD. Such disclosures will be included on our website in the “For Investors” section. Accordingly, investors should monitor that portion of our website in addition to following our press releases, SEC filings and public conference calls and webcasts.
We file periodic reports and proxy statements with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.
Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.

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Item 1A.
Risk Factors
You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our securities. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of our securities could decline and you may lose all or part of your investment.
Substantial declines in commodity prices or extended periods of low commodity prices adversely affect our business, financial condition, results of operations and cash flows and our ability to meet our capital expenditure needs and financial commitments.
The prices we receive for sales of our crude oil and natural gas production impact our revenue, profitability, access to capital, capital budget and rate of growth. Crude oil and natural gas are commodities and 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 and unpredictable. For example, during 2016 the NYMEX West Texas Intermediate ("WTI") crude oil and Henry Hub natural gas spot prices ranged from approximately $26 to $54 per barrel and $1.49 to $3.80 per MMBtu, respectively. Commodity prices may remain volatile and unpredictable in 2017.
Our crude oil sales for future periods are currently unhedged and directly exposed to continued volatility in crude oil market prices, whether favorable or unfavorable. Additionally, a portion of our natural gas sales for future periods are unhedged and directly exposed to continued volatility in natural gas market prices, whether favorable or unfavorable.
The prices we receive for sales of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
worldwide, domestic and regional economic conditions impacting the global supply of, and demand for, crude oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries and other producing nations;
the level of national and global crude oil and natural gas exploration and production activities;
the level of national and global crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;
the level and effect of trading in commodity futures markets;
the relative strength of the United States dollar compared to foreign currencies;
the price and quantity of imports of foreign crude oil;
the price and quantity of exports of crude oil or liquefied natural gas from the United States;
military and political conditions in, or affecting other, crude oil-producing and natural gas-producing countries;
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulations;
localized supply and demand fundamentals;
the cost and availability, proximity and capacity of transportation, processing, storage and refining facilities for various quantities and grades of crude oil and natural gas;
adverse weather conditions and natural disasters;
technological advances affecting energy consumption;
the effect of worldwide energy conservation and environmental protection efforts; and
the price and availability of alternative fuels or other energy sources.
Sustained material declines in commodity prices reduce our cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; may limit our ability to borrow money or raise additional capital; and may reduce our proved reserves and the amount of crude oil and natural gas we can economically produce.
In addition to reducing our revenue, cash flows and earnings, depressed prices for crude oil and natural gas may adversely affect us in a variety of other ways. If commodity prices decrease substantially, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to write down the carrying value of our crude oil and natural gas

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properties. Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating. For example in February 2016, our corporate credit rating was downgraded by Standard & Poor's Ratings Services ("S&P") and Moody's Investor Services, Inc. ("Moody's") in response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions. Those downgrades negatively impacted our cost of capital, increased our borrowing costs under our revolving credit facility and $500 million term loan due in November 2018 (“three-year term loan”), and may limit our ability to access capital markets and execute aspects of our business plans. As a result, substantial declines in commodity prices or extended periods of low commodity prices will materially and adversely affect our future business, financial condition, results of operations, cash flows, liquidity and ability to finance planned capital expenditures and commitments.
A substantial portion of our producing properties is located in limited geographic areas, making us vulnerable to risks associated with having geographically concentrated operations.
A substantial portion of our producing properties is located in the Bakken field of North Dakota and Montana, with that area comprising approximately 55% of our crude oil and natural gas production and approximately 62% of our crude oil and natural gas revenues for the year ended December 31, 2016. Approximately 46% of our estimated proved reserves were located in the Bakken as of December 31, 2016. Additionally, in recent years we have significantly expanded our operations in Oklahoma with our discovery of the SCOOP play and our increased activity in the STACK play. Our properties in Oklahoma comprised approximately 39% of our crude oil and natural gas production and approximately 31% of our crude oil and natural gas revenues for the year ended December 31, 2016. Approximately 50% of our estimated proved reserves were located in Oklahoma as of December 31, 2016.
Because of this concentration in limited geographic areas, the success and profitability of our operations may be disproportionately exposed to regional factors relative to competitors that have more geographically dispersed operations. These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the regions and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oil field services, supplies, and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the Bakken field and Oklahoma may be adversely affected by severe weather events such as floods, blizzards, ice storms and tornadoes, which can intensify competition for the items described above and may result in periodic shortages. The concentration of our operations in limited geographic areas also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the regions such as natural disasters, seismic events (which may result in third-party lawsuits), industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations and cash flows.
Volatility in the financial markets or in global economic factors could adversely impact our access to capital and 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 demand and spending. In recent years, certain global economies have experienced periods of political uncertainty, slowing economic growth, rising interest rates, changing economic sanctions, and currency volatility. These global macroeconomic conditions may put downward pressure on commodity prices and have a negative impact on our revenues, profitability, operating cash flows, liquidity and financial condition.
Historically, we have used cash flows from operations, borrowings under our revolving credit facility and proceeds from capital market transactions to fund capital expenditures. Volatility in U.S. and global financial and equity markets, including market disruptions, limited liquidity, and interest rate volatility, may negatively impact our ability to obtain needed capital on acceptable terms or at all and may increase our cost of financing. We have a revolving credit facility with lender commitments totaling $2.75 billion, which may be increased up to a total of $4.0 billion upon agreement with participating lenders. In the future, we may not be able to access adequate funding under our revolving credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments under the credit facility. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or on terms we find acceptable. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, fund our capital program and commitments, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our financial condition, results of operations and cash flows.

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Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on acceptable terms, which could lead to a decline in our crude oil and natural gas reserves, production and revenues. In addition, funding our capital expenditures with additional debt will increase our leverage and doing so with equity securities may result in dilution that reduces the value of your stock.
The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. We have budgeted $1.95 billion for capital expenditures in 2017 (excluding acquisitions which are not budgeted) of which $1.72 billion is allocated for exploration and development drilling. We may need to adjust our 2017 capital spending plans depending on market conditions.
Historically, our capital expenditures have been financed with cash generated by operations, borrowings under our revolving credit facility and proceeds from the issuance of debt and equity securities. Additionally, in 2016 non-strategic asset dispositions provided a significant source of cash that was used to reduce outstanding debt arising from our capital program. The actual amount and timing of future capital expenditures may differ materially from our estimates as a result of, among others, changes in commodity prices, available cash flows, lack of access to capital, unbudgeted acquisitions, actual drilling results, the availability of drilling and completion rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments.
Our cash flows from operations and access to capital are subject to a number of variables, including but not limited to:
the volume and value of our proved reserves;
the volume of crude oil and natural gas we are able to produce and sell from existing wells;
the prices at which crude oil and natural gas are sold;
our ability to acquire, locate and produce new reserves; and
the ability and willingness of our lenders to extend credit or of participants in the capital markets to invest in our senior notes or equity securities.
If oil and gas industry conditions weaken as a result of low commodity prices or other factors, our ability to borrow may decrease and we may have limited ability to obtain the capital necessary to sustain our operations at planned levels. Our revolving credit facility has lender commitments totaling $2.75 billion, which may be increased up to a total of $4.0 billion upon agreement with participating lenders. However, we can offer no assurance our existing or other lenders would be willing to increase their commitments under our credit facility. These lenders could decline to do so based on our financial condition, the financial condition of our industry or the economy as a whole or other reasons beyond our control. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet capital requirements and commitments, the failure to obtain additional financing could result in a curtailment of operations relating to development of our prospects, which in turn could lead to a decline in our crude oil and natural gas reserves and could adversely affect our business, financial condition, results of operations, and cash flows.
We intend to finance future capital expenditures primarily through cash flows from operations, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility or proceeds from asset sales. 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. If we issue additional debt a portion of our cash flows from operations will need to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital needs, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks, 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.

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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; not successfully cleaning out the well bore after completion of the final fracture stimulation stage; increased seismicity in areas near our completion activities and failure of our enhanced completion techniques to yield expected levels of production.
Further, many factors may curtail, delay or cancel scheduled drilling projects, including but not limited to:
abnormal pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment or qualified personnel;
shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;
delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;
mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or train derailments;
restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
decreases in, or extended periods of low, crude oil and natural gas prices;
limited availability of financing with acceptable terms;
title problems;
environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers;
limitations in infrastructure, including transportation, processing and refining capacity, or markets for crude oil and natural gas; and
delays imposed by or resulting from compliance with regulatory requirements including permitting.
Additionally, severe weather conditions and natural disasters such as flooding, tornadoes, seismic events, blizzards and ice storms affecting the areas in which we operate, including our corporate headquarters, could have a material adverse effect on our operations. The consequences of such events may include the evacuation of personnel, damage to drilling rigs or pipeline and rail transportation facilities, an inability to access well sites, destruction of information and communication systems, and the disruption of administrative and management processes, any of which could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations and cash flows
Reserve estimates depend on many assumptions that will turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company's current estimates of reserves could change, potentially in material amounts, in the future, in particular due to changes in commodity prices.
The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves for information about our estimated crude oil and natural gas reserves, PV-10, and standardized measure of discounted future net cash flows as of December 31, 2016.
In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. Our booked proved undeveloped reserves must be developed within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and may in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period. In 2016, 70 MMBoe of proved undeveloped reserves were

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removed from our year-end reserve estimates due to various factors, including removals associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking. Additionally, low commodity prices in 2016 shortened the economic lives of certain producing properties and caused certain exploration and development projects to become uneconomic, which resulted in downward reserve revisions totaling 28 MMBoe in 2016.
We must also analyze available geological, geophysical, production and engineering data in preparing reserve estimates. The extent, quality and reliability of this data can vary which in turn can affect our ability to model the porosity, permeability and pressure relationships in unconventional resources. The process also requires economic assumptions, based on historical data but projected into the future, about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
The prices used in calculating our estimated proved reserves are calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the year ended December 31, 2016, average prices used to calculate our estimated proved reserves were $42.75 per Bbl for crude oil and $2.49 per MMBtu for natural gas ($35.57 per Bbl for crude oil and $2.14 per Mcf for natural gas adjusted for location and quality differentials). Actual future prices may be materially higher or lower than those used in our year-end estimates. NYMEX WTI crude oil and Henry Hub natural gas spot prices averaged $52.50 per barrel and $3.30 per MMBtu, respectively, for the month of January 2017. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities for proved reserve sensitivities under certain increasing and decreasing commodity price scenarios.
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 activities, 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. 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 average prices used in the calculations. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities for Standardized Measure and PV-10 sensitivities under certain increasing and decreasing commodity price scenarios.
Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:
the actual prices we receive for sales of crude oil and natural gas;
the actual cost and timing of development and production expenditures;
the timing and amount of actual production; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of costs 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 use of a 10% discount factor, which is required by the SEC to be used to calculate discounted future net revenues for reporting purposes, 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. Any significant variances in timing or assumptions could materially affect the estimated present value of our reserves, which in turn could have an adverse effect on the value of our assets.

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We may be required to further write down the carrying values of our crude oil and natural gas properties if commodity prices decline or our development plans change.
Accounting rules require we periodically review the carrying values of our crude oil and natural gas properties for possible impairment. Proved properties are reviewed for impairment on a field-by-field basis each quarter. We use the successful efforts method of accounting whereby the estimated future cash flows expected in connection with a field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model.
Based on specific market factors, prices, and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying values of our crude oil and natural gas properties. A write-down results in a non-cash charge to earnings. We have incurred impairment charges in the past and may incur additional impairment charges in the future, particularly if commodity prices decline, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our cash flows and results of operations.
Unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.
The unavailability or high cost of drilling rigs, well completion crews, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.
In the regions in which we operate, there have historically been shortages of drilling rigs, well completion crews, equipment, supplies, personnel or oilfield services, including key components used in fracture stimulation processes such as water and proppants, as well as high costs associated with these critical components of our operations. As a result of the significant decrease in commodity prices in recent years, the number of providers of the materials and services described above has decreased in the regions where we operate. As a result, the likelihood of experiencing shortages or higher costs of materials and services may further increase in connection with any period of commodity price recovery. Such shortages or high costs could delay the execution of our drilling and development plans, including our plans to work down our large inventory of uncompleted wells, or cause us to incur expenditures not provided for in our capital budget or to not achieve the rates of return we are targeting for our development program, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may incur substantial losses and be subject to substantial liability claims as a result of our crude oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and under-insured events could materially and adversely affect our business, financial condition or results of operations. Our crude oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:
environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
fires, explosions and ruptures of pipelines;
loss of product or property damage occurring as a result of transfer to a rail car or train derailments;
personal injuries and death;
adverse weather conditions and natural disasters; and

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spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
injury or loss of life;
damage to or destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations;
repair and remediation costs; and
litigation.
We may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks are generally not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Prospects we decide to drill may not yield crude oil or natural gas in economically producible quantities.
Prospects we decide to drill that do not yield crude oil or natural gas in economically producible quantities may adversely affect our results of operations and financial condition. In this report, we describe some of our current prospects and plans to explore and develop those prospects. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect requiring substantial additional seismic data processing and interpretation. It is not possible to predict with certainty whether any particular prospect will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or be economically producible. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in economically producible quantities. We cannot assure you the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of uncertainties, including crude oil and natural gas prices; the availability of capital, drilling rigs, well completion crews, and transportation capacity; costs; drilling results; regulatory approvals; and other factors. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations in sufficient quantities to achieve an economic return. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. Low commodity prices, reduced capital spending, lack of available drilling and completion rigs and crews, and numerous other factors, many of which are beyond our control, could result in our failure to establish production on undeveloped acreage, and, if we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents 66% of our total net undeveloped acreage at December 31, 2016. At that date, we had leases representing 275,646 net acres expiring in 2017, 110,597 net acres expiring in 2018, and 130,696 net acres expiring in 2019. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Our proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2016, approximately 59% of our total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2016 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of

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approximately $6.3 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any proved undeveloped reserves not developed within this five-year time frame. Such removals have occurred in the past and may occur in the future. A removal of such reserves could adversely affect our operations. In 2016, 70 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates due to various factors, including removals associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking. Additionally, low commodity prices in 2016 caused certain exploration and development projects to become uneconomic, which resulted in downward revisions of proved undeveloped reserves totaling 28 MMBoe in 2016.
Our business depends on crude oil and natural gas transportation, processing, and refining facilities, most of which are owned by third parties, and on the availability of rail transportation.
The value we receive for our crude oil and natural gas production depends in part on the availability, proximity and capacity of gathering, pipeline and rail systems and processing and refining facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. Although we have some contractual control over the transportation of our products, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made for the sale or delivery of our products.
The disruption of transportation, processing or refining facilities due to labor disputes, maintenance, civil disturbances, public protests, terrorist attacks, cyber attacks, adverse weather, natural disasters, seismic events, changes in tax and energy policies, federal, state and international regulatory developments, changes in supply and demand, equipment failures or accidents, including pipeline and gathering system ruptures or train derailments, and general economic conditions could negatively impact our ability to achieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such facilities would be restored or the impact on prices in the areas we operate. A significant shut-in of production in connection with any of the aforementioned items could materially affect our cash flows, and if a substantial portion of the impacted production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows.
We transport a portion of the operated crude oil production from our North region to market centers using rail transportation facilities owned and operated by third parties, with approximately 8% of such production being shipped by rail in December 2016. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Regulation of sales and transportation of crude oil and natural gas liquids for a discussion of regulations impacting the transportation of crude oil by rail. Compliance with regulations, including voluntary measures adopted by the railroad industry, impacting 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 specifications. We do not currently own or operate rail transportation facilities or rail cars; however, compliance with regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.
Our business depends on the availability of water and the ability to dispose of waste water from oil and gas activities. Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.
With current technology, water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought), or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection wells.
In addition, concerns have been raised about the potential for seismic events to occur from the use of underground injection wells, a predominant method for disposing of waste water from oil and gas activities. New rules and regulations have been developed to address these concerns by limiting or eliminating the ability to use disposal wells in certain locations or increasing

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the cost of disposal. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations. Some states, including states in which we operate, have delayed permit approvals, mandated a reduction in injection volumes, or have shut down or imposed moratoria on the use of injection wells. Regulators in some states, including states in which we operate, are considering additional requirements related to seismicity. For example, in Oklahoma, the Oklahoma Corporation Commission ("OCC") has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of the state. These rules require disposal well operators, among other things, to conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma has adopted a “traffic light” system, wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted.
Compliance with existing or new environmental regulations and permit requirements governing the withdrawal, storage, and use of water necessary for hydraulic fracturing of wells or the disposal of waste water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our crude oil and natural gas exploration and production operations are subject to complex and stringent federal, state and local laws and regulations, including those governing environmental protection, the occupational health and safety aspects of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a description of the laws and regulations that affect us. In order to conduct operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Environmental regulations may restrict the types, quantities and concentration of materials released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenues.
Failure to comply with laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations and litigation. Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
Moreover, our costs of compliance with existing laws could be substantial and may increase, or unforeseen liabilities could be imposed, if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
Climate change legislation or regulations governing the emissions of “greenhouse gases” could result in increased operating costs and reduce demand for the crude oil, natural gas and natural gas liquids we produce.
In response to EPA findings that emissions of carbon dioxide, methane and other greenhouse gases endanger human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act establishing, among other things, Prevention of Significant Deterioration ("PSD") and construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for greenhouse gas emissions are also required to meet “best available control technology” standards established on a case-by-case basis. Although we currently do not have any facilities required to adhere to PSD or Title V permit requirements, a change in our operational approach to constructing new facilities could trigger Title V and/or PSD requirements for a multi-well pad facility with substantial production or centralized production facilities. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Air emissions and climate change for further discussion of the laws and regulations that affect us with respect to climate change initiatives. EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

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While Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal legislation, a number of state and regional efforts have emerged that are aimed at tracking and reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting greenhouse gases. There has also been discussion of imposing a federal carbon tax on fossil fuel emissions.
The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the crude oil and natural gas we produce, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods or other climatic events. If any such effects were to occur as a result of climate change or otherwise, they could have an adverse effect on our assets and operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and inability to book future reserves.
Hydraulic fracturing is an important and commonly used process in the completion of crude oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the high-pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. In recent years there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and to induce seismic events. As a result, several federal and state agencies are considering legislation that would increase the regulatory burden imposed on hydraulic fracturing. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Hydraulic fracturing for a description of the laws and regulations that affect us with respect to hydraulic fracturing.
Several states, including states in which we operate, have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating or prohibiting the time, place and manner of drilling activities or hydraulic fracturing activities. 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 to 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, which would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Proposed legislation and regulations under consideration could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.
Changes to existing laws or regulations, new laws or regulations, or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products. Similarly, changes in regulatory policies and priorities could result in the imposition of new obligations upon us, such as increased reporting or audits. Any of these requirements could result in increased operating costs and could have a material adverse effect on our financial condition and results of operations. If such legislation, regulations or other requirements are adopted, they could result in, among other items, additional restrictions on hydraulic fracturing of wells, restrictions on the disposal of waste water from oil and gas activities, restrictions on emissions of greenhouse gases, changes to the calculation of royalty payments, new safety requirements such as those involving rail transportation, and additional regulation of private energy commodity derivative and hedging activities. These and other potential laws, regulations and other requirements could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. This, in turn, could have a material adverse effect on our financial condition, results of operations and cash flows.

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Future legislation may impose new taxes on crude oil or natural gas activities, including by eliminating or reducing certain federal income tax deductions currently available with respect to crude oil and natural gas exploration and development.
In recent years, legislation has been proposed to make significant changes to U.S. federal income tax laws, including the elimination or deferral of certain U.S. federal income tax deductions currently available to crude oil and natural gas exploration and production companies. Such proposed changes have included, but have not been not limited to: (i) the repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and exploration and development costs; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures.
It is uncertain whether these or similar changes will be enacted or, if enacted, how soon any such changes would become effective. The passage of such legislation or any other similar change in U.S. federal income tax law could eliminate or defer certain available tax deductions within our industry, and any such changes could adversely affect our financial condition, results of operations and cash flows. Additionally, in 2016 the U.S. Federal government proposed to impose a per barrel oil fee that would be collected on domestically produced and imported petroleum products. Such proposal was not enacted into law. Nonetheless, the introduction and enactment of similar proposals in the future could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices companies such as ours receive for our crude oil.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, and seismicity may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to conduct our business.
Regulations under the Dodd-Frank Act regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risk and other risks associated with our business.
From time to time, we may use derivative instruments to manage commodity price risk. In 2010, the U.S. Congress adopted the Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This financial reform legislation includes provisions that require many derivative transactions previously executed over-the-counter to be executed through an exchange and be centrally cleared. In addition, this legislation calls for the imposition of position limits for swaps, including swaps involving physical commodities such as crude oil and natural gas, which have been proposed but have not been finalized. It also establishes minimum margin requirements for uncleared swaps for swap dealers and major swap participants.
If we do not qualify for an end user exemption from the Dodd-Frank requirements, the new regulations could significantly increase the cost of derivative contracts, 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. Additionally, 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. Further, if we do not qualify for an end user exemption, the margin requirements for uncleared swaps may require us to post collateral, which could adversely affect our available liquidity. If our use of derivatives becomes limited as a result of the regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower crude oil or natural gas prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows.

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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. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Energy conservation measures or initiatives that stimulate demand for alternative forms of energy could reduce the demand for the crude oil and natural gas we produce.
Fuel conservation measures, climate change initiatives, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices could reduce demand for the crude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The loss of senior management or technical personnel could adversely affect our operations.
We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2016, non-operated properties represented 20% of our estimated proved developed reserves, 7% of our estimated proved undeveloped reserves, and 12% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including compliance with environmental, safety and other regulations, or the amount of expenditures required to fund the development and operation of such properties. Moreover, we are dependent on other working interest owners on these projects to fund their contractual share of capital and operating expenditures. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and could have a material adverse effect on our financial condition, results of operations and cash flows.
Our revolving credit facility, three-year term loan, and indentures for our senior notes contain certain covenants and restrictions that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our goals.
Our revolving credit facility and three-year term loan contain restrictive covenants that limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, and merge, consolidate or sell all or substantially all of our assets. Our revolving credit facility and three-year term loan also contain a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity plus, to the extent resulting in a reduction of total shareholders' equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014.
At December 31, 2016, our consolidated net debt to total capitalization ratio, as defined, was 0.57 to 1.00. Our total debt would need to independently increase by approximately $2.8 billion above the existing level at December 31, 2016 (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders' equity would need to independently decrease by approximately $1.5 billion below the existing level at December 31, 2016 (excluding the after-tax impact of any non-cash impairment charges) to reach the maximum covenant ratio.

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The indentures governing our senior notes contain covenants that, among other things, limit our ability to create liens securing certain indebtedness, enter into certain sale and leaseback transactions, and consolidate, merge or transfer certain assets.
The covenants in our revolving credit facility, three-year term loan, and senior note indentures may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facility, three-year term loan, or senior note indentures may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility, three-year term loan, or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, could result in all amounts outstanding thereunder, together with accrued interest, to be due and payable. If our indebtedness is accelerated, our assets may not be sufficient to repay in full such indebtedness, which would adversely affect our financial condition and results of operations.
Increases in interest rates could adversely affect our business.
Our business and operating results can be adversely affected by factors such as the availability, terms of and cost of capital, increases in interest rates, or a downgrade or other negative rating action with respect to our credit rating. In February 2016, our corporate credit rating was downgraded by S&P and Moody's in response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions. Those downgrades caused the interest rates on our revolving credit facility borrowings and three-year term loan to increase by 0.250% and 0.125%, respectively, and may limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. As of January 31, 2017, outstanding variable rate borrowings under our revolving credit facility and three-year term loan totaled $1.34 billion and the impact of a 0.25% increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $3.4 million and a $2.1 million decrease in our annual net income. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our financial condition and results of operations.
The inability of joint interest owners, derivative counterparties, significant customers, and service providers 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, crude oil refining companies, and natural gas gathering and processing companies ($405 million in receivables at December 31, 2016); our joint interest and other receivables ($365 million at December 31, 2016); and counterparty credit risk associated with our derivative instrument receivables, if any.
Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells.
We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with significant customers. The largest purchaser of our crude oil and natural gas during the year ended December 31, 2016 accounted for approximately 18% of our total crude oil and natural gas revenues for the year. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Additionally, our use of derivative instruments involves the risk that our counterparties will be unable to meet their obligations.
Finally, we rely on oilfield service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A worsening of the current commodity price environment may result in a material adverse impact on the liquidity and financial position of the parties with whom we do business, resulting in delays in payment of, or non-payment of, amounts owed to us, delays in operations, loss of access to equipment and facilities and similar impacts. These events could have an adverse impact on our financial condition, results of operations and cash flows.
Our derivative activities could result in financial losses or reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in commodity prices, from time to time we may enter into derivative instruments for a portion of our production. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments for a summary of our commodity derivative positions as of December 31, 2016. We do not designate any of our derivative instruments as hedges for accounting purposes and we record all derivatives on our balance sheet at fair value. Changes in the fair value of our derivatives are recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in commodity prices and resulting changes in the fair value of our derivatives.
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;

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the counterparty to the derivative instrument defaults on its contractual obligations; or
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, our derivative arrangements limit the benefit we would receive from increases in commodity prices. Our decision on the quantity and price at which we choose to hedge our future production, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to hedge future production if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities in order to monetize gain positions for the purpose of funding our capital program. Our crude oil sales for future periods are currently unhedged and directly exposed to continued volatility in crude oil market prices, whether favorable or unfavorable. Additionally, a portion of our natural gas sales for future periods are unhedged and directly exposed to continued volatility in natural gas market prices, whether favorable or unfavorable.
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 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 have been and may continue to be the target of cyber attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release or theft of confidential or protected information, corruption of data or other disruptions of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber attack involving our information systems and related infrastructure, or that of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to:
unauthorized access to or theft of seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;
data corruption or operational disruption of production-related infrastructure could result in a 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 third party gathering, pipeline, or rail transportation systems could delay or prevent us from transporting and 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 our knowledge we have not experienced any material losses relating to cyber attacks; however, there can be no assurance that we will not suffer material 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.
A limited liability company for which our Chairman and Chief Executive Officer serves as sole manager beneficially owns approximately 76% 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, 2016, a limited liability company for which Harold G. Hamm, our Chairman and Chief Executive Officer, serves as sole manager beneficially owned approximately 76% of our outstanding common shares. As a result, Mr. Hamm has control over our Company 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. Therefore, Mr. Hamm could cause, delay or prevent a change of control of our Company. The interests of Mr. Hamm and the limited liability company for which he serves as sole manager may not coincide with the interests of other holders of our common stock.

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We have historically entered into, and may enter into, transactions from time to time with companies affiliated with Mr. Hamm if, after an independent review by our Audit Committee or by the independent members of our Board of Directors, 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 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 new or emerging 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 may be subject to risks in connection with acquisitions.
The successful acquisition of producing properties requires an assessment of several factors, including but not limited to:
recoverable reserves;
future crude oil and natural gas prices and location and quality differentials;
the quality of the title to acquired properties;
future development costs, operating costs and property taxes; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review, which we believe to be generally consistent with industry practices, of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations.



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Item 1B.    Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2016.
 
Item 2.
Properties
The information required by Item 2 is contained in Part I, Item 1. Business—Crude Oil and Natural Gas Operations and is incorporated herein by reference.

Item 3.
Legal Proceedings
See Note 10. Commitments and Contingencies–Litigation in Part II, Item 8. Financial Statements and Supplementary Data–Notes to Consolidated Financial Statements for a discussion of the legal matter involving the Company, Billy J. Strack and Daniela A. Renner, which is incorporated herein by reference.

Item 4.
Mine Safety Disclosures
Not applicable.

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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. 
 
 
2016
 
2015
 
 
Quarter Ended
 
Quarter Ended
 
 
March 31
 
June 30
 
September 30
 
December 31
 
March 31
 
June 30
 
September 30
 
December 31
High
 
$
31.90

 
$
46.01

 
$
52.78

 
$
60.30

 
$
48.99

 
$
53.65

 
$
42.51

 
$
38.16

Low
 
$
13.94

 
$
28.63

 
$
40.92

 
$
44.37

 
$
32.51

 
$
41.74

 
$
22.56

 
$
19.60

Cash Dividend
 

 

 

 

 

 

 

 

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. As of January 31, 2017, the number of record holders of our common stock was 1,094. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately 57,900. On January 31, 2017, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $48.56 per share.
The following table summarizes our purchases of our common stock during the quarter ended December 31, 2016:
Period
 
Total number of
shares purchased (1)
 
Average
price paid
per share (2)
 
Total number of shares
purchased as part of
publicly announced
plans or programs
 
Maximum number of
shares that may yet be
purchased under the
plans or programs
October 1, 2016 to October 31, 2016
 
401

 
$
53.22

 

 

November 1, 2016 to November 30, 2016
 
40,714


$
48.83