10-K 1 clr201710-k.htm FORM 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, 2017
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
_______________________________ 
logoa01a04.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 each class
 
Name of each exchange on which registered
Common Stock, $0.01 par value
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
_______________________________ 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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
 
¨
 
 
 
 
 
 
 
 
 
 
 
Emerging growth company
 
¨
 
 
 
 
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
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, 2017 was approximately $2.8 billion, based upon the closing price of $32.33 per share as reported by the New York Stock Exchange on such date.
375,215,902 shares of our $0.01 par value common stock were outstanding on January 31, 2018.

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 2018, 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.

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“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.
“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 optimized 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, property acquisitions and dispositions, or joint development opportunities;
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) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
We were formed in 1967 to explore for, develop and produce crude oil and natural gas properties. Through the 1980s, our activities and growth remained focused primarily in Oklahoma. In the 1980s, we expanded our activity into the North region. The North region comprised approximately 59% 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, 2017. The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. Approximately 50% of our estimated proved reserves as of December 31, 2017 are located in the North region. In recent years, we have significantly expanded our operations in our South region with our increased activity in the SCOOP and STACK plays. The South region comprised approximately 41% 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, 2017.
We focus our exploration activities in large new or developing crude oil and 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, 2017, our estimated proved reserves were 1,331 MMBoe, with estimated proved developed reserves of 602 MMBoe, or 45% of our total estimated proved reserves. Crude oil represents approximately 48% of our estimated proved reserves as of December 31, 2017. The standardized measure of our discounted future net cash flows totaled approximately $10.5 billion at December 31, 2017.
For 2017, we generated crude oil and natural gas revenues of $2.98 billion and operating cash flows of $2.08 billion. Crude oil accounted for approximately 57% of our total production and approximately 78% of our crude oil and natural gas revenues for 2017. Production averaged 242,637 Boe per day for 2017, a 12% increase compared to average production of 216,912 Boe per day for 2016. Average daily production for the quarter ended December 31, 2017 increased 37% to 286,985 Boe per day compared to 209,861 Boe per day for the quarter ended December 31, 2016 due to increased drilling and completion activities.
The table below summarizes our total estimated proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, 2017, average daily production for the quarter ended December 31, 2017 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, 2017
 
Average daily
production for
fourth quarter
2017
(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
 
594,818

 
44.7
%
 
$
6,488

 
1,313

 
158,640

 
55.3
%
 
10.3

Montana Bakken
 
40,703

 
3.1
%
 
412

 
263

 
6,958

 
2.4
%
 
16.0

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
28,998

 
2.2
%
 
340

 
130

 
7,022

 
2.4
%
 
11.3

Other Red River units
 
2,668

 
0.2
%
 
28

 
117

 
2,475

 
0.9
%
 
3.0

Other
 
1,356

 
0.1
%
 
9

 
8

 
468

 
0.2
%
 
7.9

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
491,776

 
36.9
%
 
3,597

 
260

 
62,242

 
21.7
%
 
21.6

STACK
 
167,390

 
12.6
%
 
936

 
160

 
47,914

 
16.7
%
 
9.6

Other
 
3,286

 
0.2
%
 
23

 
175

 
1,266

 
0.4
%
 
7.1

Total
 
1,330,995

 
100.0
%
 
$
11,833

 
2,426

 
286,985

 
100.0
%
 
12.7

 
(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 $1.4 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 2017 production into estimated proved reserve volumes as of December 31, 2017.
Business Environment and Outlook
Our industry has been significantly impacted by lower commodity prices in recent years. The downward pressure on prices experienced in 2015 and 2016 showed signs of easing in 2017. Commodity prices remained volatile during the year, but generally increased on average in 2017 relative to 2016 in response to improving domestic and global supply and demand fundamentals and other factors. Crude oil prices in particular showed significant signs of improvement in late 2017 and early 2018, with West Texas Intermediate crude oil benchmark prices reaching a three-year high of $66 per barrel in January 2018. Crude oil prices remain volatile and it is uncertain whether the increase in market prices experienced in recent months will be sustained.
Continental marked its 50th anniversary in the oil and gas business in 2017. Our leadership team has significant experience with operating in challenging commodity price environments. With our portfolio of high quality assets, we are well-positioned to manage the ongoing challenges and price volatility facing our industry.
For 2018, our primary business strategies will focus on:
Balancing strong production growth with free cash flow generation;
Enhancing cash flows and return on capital employed through improvements in operating efficiencies, technical innovations, and optimized completion methods;
Continuing to exercise disciplined capital spending to maintain financial flexibility and ample liquidity; and
Improving debt metrics by further reducing outstanding debt using available operating cash flows or proceeds from asset dispositions or joint development arrangements.
Based on an expectation for higher operating cash flows in 2018 in response to improvement in crude oil prices in late 2017 and early 2018, we have increased our planned non-acquisition capital spending for 2018 to $2.3 billion compared to $2.0 billion spent in 2017, with approximately 78% of our 2018 drilling and completion budget focusing on oil-weighted areas in

2



the North Dakota Bakken and SCOOP Springer plays. We expect to fund our budgeted spending using cash flows from operations. We may adjust our pace of drilling and development as 2018 market conditions evolve.
For 2018, we plan to operate an average of approximately 21 drilling rigs and 10 completion crews for the year. We expect to spend approximately 52% of our 2018 capital expenditures budget on drilling and completion activities in North Dakota Bakken, 20% in SCOOP, and 14% in STACK. The remaining 14% of our 2018 budget will target other capital expenditures such as leasing and renewals, work-overs, and facilities. See the section below titled Summary of Crude Oil and Natural Gas Properties and Projects for further discussion of our 2018 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 balancing production growth with free cash flow generation. We hold a portfolio of leasehold acreage, drilling opportunities and uncompleted wells in certain premier U.S. resource plays with varying access 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 deliver strong production growth while generating cash flows in excess of operating and capital requirements, to work down our large inventory of uncompleted wells, to convert our undeveloped acreage to acreage held by production, and to 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 natural gas areas that provide attractive rates of return.
Enhance cash flows and return on capital employed through costs reductions, operating efficiencies, technical innovations, and optimized 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.
We continued to achieve efficiency gains in various aspects of our business in 2017, including additional reductions in spud-to-total depth drilling times and average days to drill horizontal laterals, which has led to reductions in drilling costs in our core areas. In addition to lowering our drilling costs, we also work to enhance cash flows through the use of optimized 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 2017, we reduced our total debt by $226 million, or 3%, from $6.58 billion at year-end 2016 to $6.35 billion at year-end 2017. We are actively targeting further debt reduction using available cash flows from operations or proceeds from potential sales of non-strategic assets and joint development opportunities and will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.
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, 2015 through December 31, 2017, our proved reserve additions through extensions and discoveries were 743 MMBoe compared with insignificant 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 598,400 net undeveloped acres and 1.19 million net developed acres under lease as of December 31, 2017 concentrated in certain premier U.S. resource plays. We are among the largest leaseholders in the Bakken, SCOOP and STACK plays. Being an early entrant in these plays has allowed us to capture significant acreage positions in core parts of the plays.

3



Expertise with Horizontal Drilling and Optimized Completion Methods. We have substantial experience with horizontal drilling and optimized completion methods and continue to be among 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. We have also been among industry leaders in testing and utilizing optimized completion technologies involving various combinations of fluid types, proppant types and volumes, and stimulation stage spacing 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, 2017, we operated properties comprising 89% 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 9 senior officers have an average of 38 years of oil and gas industry experience.
Financial Position and Liquidity. Currently we have a revolving credit facility with lender commitments totaling $2.75 billion that matures in May 2019. We had approximately $2.65 billion of available borrowing capacity under our credit facility at January 31, 2018 after considering outstanding borrowings and letters of credit.
Our 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 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 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, production, seismic, 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, 2017. The standardized measure of our discounted future net cash flows totaled approximately $10.5 billion at December 31, 2017. Our reserve estimates as of December 31, 2017 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 96% of our PV-10 and 96% of our total proved reserves as of December 31, 2017. 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, 2017 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2017 through December 2017, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas ($47.03 per Bbl for crude oil and $3.00 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
 
318,291

 
1,697,926

 
601,279

 
$
7,474.9

Proved developed non-producing
 
416

 
1,235

 
622

 
6.4

Proved undeveloped
 
322,242

 
2,441,120

 
729,094

 
4,352.2

Total proved reserves
 
640,949

 
4,140,281

 
1,330,995

 
$
11,833.5

Standardized Measure (1)
 
 
 
 
 
 
 
$
10,470.2

 
(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 $1.4 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, 2017. 
 
 
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
 
217,776

 
472,057

 
296,452

 
212,107

 
517,562

 
298,366

Montana Bakken
 
21,503

 
38,480

 
27,916

 
10,385

 
14,412

 
12,787

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
28,321

 
4,058

 
28,998

 

 

 

Other Red River units
 
2,667

 
16

 
2,668

 

 

 

Other
 
110

 
7,469

 
1,356

 

 

 

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
35,333

 
754,820

 
161,136

 
84,828

 
1,474,871

 
330,640

STACK
 
12,181

 
407,448

 
80,089

 
14,922

 
434,275

 
87,301

Other
 
816

 
14,813

 
3,286

 

 

 

Total
 
318,707

 
1,699,161

 
601,901

 
322,242

 
2,441,120

 
729,094

The following table provides information regarding changes in total estimated proved reserves for the periods presented.  
 
 
Year Ended December 31,
MBoe
 
2017
 
2016
 
2015
Proved reserves at beginning of year
 
1,274,864

 
1,225,811

 
1,351,091

Revisions of previous estimates
 
(82,012
)
 
(110,474
)
 
(297,198
)
Extensions, discoveries and other additions
 
240,206

 
249,430

 
253,173

Production
 
(88,562
)
 
(79,390
)
 
(80,926
)
Sales of minerals in place
 
(15,197
)
 
(10,513
)
 
(329
)
Purchases of minerals in place
 
1,696

 

 

Proved reserves at end of year
 
1,330,995

 
1,274,864

 
1,225,811

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 and differentials, operating costs, or development costs.
Given the significant volatility in commodity prices in recent years, and given the uncertainty regarding the timing, magnitude and duration 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. In light of our strategy to preserve financial flexibility and minimize the incurrence of new debt, we maintained a disciplined spending approach in 2017 and continued to refine our capital program to focus on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. As part of this effort, we shifted a portion of our 2017 spending away from the SCOOP and Bakken plays to areas in the emerging STACK play that offered more advantageous opportunities and rates of return in the 2017 commodity price environment. This shift in strategy coupled with our increased emphasis on balancing capital spending with cash flows altered the timing and extent of our previous development plans in certain areas and resulted in the removal of 41 MMBo and 290 Bcf (totaling 89 MMBoe) of PUD reserves no longer scheduled to be developed within five years from the date of initial booking. These removals do not 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 further improvement in commodity prices and an expansion of our capital expenditure budget.
Commodity prices increased on average in 2017 relative to 2016 in response to improving domestic and global supply and demand fundamentals and other factors. The 12-month average first-day-of-the-month price for crude oil increased 20% from $42.75 per Bbl for 2016 to $51.34 per Bbl for 2017, while the 12-month average first-day-of-the-month price for natural gas increased 20% from $2.49 per MMBtu for 2016 to $2.98 per MMBtu for 2017. These changes increased the economic lives of

6



certain producing properties and caused certain previously uneconomic projects to become economic, which had a favorable impact on the Company’s proved reserve estimates, resulting in upward revisions of 29 MMBo and 78 Bcf (totaling 42 MMBoe) in 2017.
Additionally, changes in anticipated production performance on certain properties resulted in 59 MMBo of downward revisions to crude oil reserves and 173 Bcf of upward revisions to natural gas reserves (netting to 30 MMBoe of downward revisions) in 2017. Further, changes in ownership interests, operating costs, and other factors during the year resulted in 7 MMBo of downward revisions to crude oil reserves and 11 Bcf of upward revisions to natural gas reserves (netting to 5 MMBoe of downward revisions) in 2017.
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 and completion activities in the Bakken, SCOOP and STACK areas. Proved reserve additions from our drilling activities in the Bakken totaled 148 MMBoe, 73 MMBoe and 96 MMBoe for 2017, 2016 and 2015, respectively, while reserve additions in SCOOP totaled 53 MMBoe, 97 MMBoe and 93 MMBoe for 2017, 2016 and 2015, respectively. Additionally, extensions and discoveries were impacted by successful drilling and completion results in the STACK play, resulting in proved reserve additions of 39 MMBoe, 79 MMBoe and 57 MMBoe in 2017, 2016 and 2015, respectively. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2017 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, 2017 are located in the Bakken, SCOOP, and STACK plays, our most active development areas, with those plays comprising 43%, 45%, and 12%, respectively, of our total PUD reserves at year-end 2017. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2017. Our PUD reserves at December 31, 2017 include 70 MMBoe of reserves associated with wells where drilling has occurred but the wells have not been completed or are completed but not producing ("DUC wells"). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells.
 
 
Crude Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
Proved undeveloped reserves at December 31, 2016
 
353,018

 
2,419,198

 
756,218

Revisions of previous estimates
 
(73,684
)
 
(131,306
)
 
(95,569
)
Extensions and discoveries
 
100,874

 
492,468

 
182,952

Sales of minerals in place
 
(3,441
)
 
(24,870
)
 
(7,586
)
Purchases of minerals in place
 
149

 
3,009

 
650

Conversion to proved developed reserves
 
(54,674
)
 
(317,379
)
 
(107,571
)
Proved undeveloped reserves at December 31, 2017
 
322,242

 
2,441,120

 
729,094

Revisions of previous estimates. During the year ended December 31, 2017, we removed 165 gross (123 net) PUD locations, which resulted in the removal of 41 MMBo and 290 Bcf (totaling 89 MMBoe) of PUD reserves, of which 31 MMBo and 66 Bcf (totaling 42 MMBoe) was related to our Bakken properties and 10 MMBo and 218 Bcf (totaling 46 MMBoe) was related to our SCOOP properties. These removals were due to the aforementioned refinement of our drilling program to place emphasis on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. These and other aforementioned factors altered the timing and extent of our previous development plans in certain

7



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, increases in average crude oil and natural gas prices in 2017 caused certain previously uneconomic projects to become economic, which resulted in upward PUD reserve revisions of 8 MMBo and 22 Bcf (totaling 11 MMBoe) in 2017. Further, changes in anticipated production performance on producing properties having offsetting PUD locations resulted in 43 MMBo of downward revisions to crude oil PUD reserves and 134 Bcf of upward revisions to natural gas PUD reserves (netting to 20 MMBoe of downward revisions) in 2017. Finally, changes in ownership interests, operating costs, and other factors during the year resulted in 3 MMBo of upward revisions to crude oil PUD reserves and 3 Bcf of upward revisions to natural gas PUD reserves (totaling 3 MMBoe of upward revisions) in 2017.
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 86 MMBo and 216 Bcf (totaling 122 MMBoe) in 2017, while SCOOP PUD reserve additions totaled 13 MMBo and 193 Bcf (totaling 45 MMBoe), and STACK PUD reserve additions totaled 2 MMBo and 83 Bcf (totaling 16 MMBoe). See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2017 drilling activities in these areas.
Conversion to proved developed reserves. In 2017, we developed approximately 17% of our PUD locations and 14% of our PUD reserves booked as of December 31, 2016 through the drilling and completion of 300 gross (146 net) development wells at a capital cost of approximately $762 million incurred in 2017. PUD conversions in North Dakota Bakken totaled 49 MMBo and 106 Bcf (totaling 66 MMBoe) in 2017, while STACK PUD conversions totaled 4 MMBo and 130 Bcf (totaling 26 MMBoe) and SCOOP PUD conversions totaled 2 MMBo and 81 Bcf (totaling 15 MMBoe).
Given the continued volatility in crude oil prices during the year, we chose not to significantly advance the development of our oil-weighted properties in the SCOOP play in 2017, instead choosing to defer development capital in that play to future periods when prices become more stable and sustainable. Additionally, we deferred certain well completion activities in North Dakota Bakken in 2017 and our inventory of DUC wells that built up in that play in 2016 was not reduced to the extent originally planned for the year. These factors adversely impacted our conversion of PUD reserves to proved developed reserves in 2017.
At December 31, 2016, we had 95 MMBoe of PUD reserves associated with 279 gross (145 net) operated and non-operated DUC locations at that date. A portion of those locations, representing 18 MMBoe of PUD reserves, were not completed in 2017 and are not reflected as having been converted to proved developed reserves during the year and continue to be reflected as PUD locations at December 31, 2017. If the year-end 2016 DUC wells had been fully completed and converted to proved developed locations in 2017, our 2017 PUD reserve conversion rate of 14% would have been 17%.
Our inventory of DUC wells classified as PUDs total 278 gross (105 net) operated and non-operated locations at December 31, 2017, representing 70 MMBoe, or 10%, of our PUD reserves. The following table summarizes 2017 activity associated with DUC wells that are classified as PUD reserves.
 
 
DUC Wells
 
 
Gross
 
Net
 
PUD Reserves
(MBoe)
DUC wells at December 31, 2016
 
279

 
145

 
95,272

Wells converted to proved developed reserves
 
(203
)
 
(110
)
 
(75,274
)
Wells added
 
209

 
72

 
51,306

Revisions
 
(7
)
 
(2
)
 
(1,707
)
DUC wells at December 31, 2017
 
278

 
105

 
69,597

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, a substantial portion of our future capital expenditures will be focused on developing our PUD locations, including our drilled but not completed locations. The costs to drill our uncompleted wells were incurred prior to December 31, 2017 and only the remaining completion costs are included in future development plans.

8



Estimated future development costs relating to the development of PUD reserves are projected to be approximately $1.0 billion in 2018 (44% of total capital budget), $1.5 billion in 2019, $1.7 billion in 2020, $1.5 billion in 2021, and $0.7 billion in 2022. These capital expenditure projections are reflective of the current commodity price environment and have been established based on an expectation of drilling and completion costs, available cash flows, and borrowing capacity. Development of our existing PUD reserves at December 31, 2017, including those associated with DUC 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 changes in business strategy, depressed commodity prices, or for other reasons have been removed from our reserves at December 31, 2017. We had no PUD reserves at December 31, 2017 that remain undeveloped beyond five years from the date of initial booking.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Ryder Scott, our independent reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 96% of our PV-10 and 96% of our total proved reserves as of December 31, 2017 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 reserves 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 reserves estimates. Proved reserves 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 reserves report and on a semi-annual basis review any internal proved reserves 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 33 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 reserves estimates are reviewed and approved by the Company's President and certain other members of senior management.
Proved Reserve, Standardized Measure, and PV-10 Sensitivities
Our year-end 2017 proved reserve, Standardized Measure, and PV-10 estimates were prepared using 2017 average first-day-of-the-month prices of $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas ($47.03 per Bbl for crude oil and $3.00 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.
Provided below are sensitivities illustrating the potential impact on our estimated proved reserves, Standardized Measure, and PV-10 at December 31, 2017 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 2017 average first-day-of-the-month price of $2.98 per MMBtu.

9



chart-a506cdca71be5327bdd.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 2017 average first-day-of-the-month price of $51.34 per Bbl.
chart-d9edf235845e5fa6823.jpg

11



Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2017: 
 
 
Developed acres
 
Undeveloped acres
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
951,645

 
556,044

 
147,513

 
90,288

 
1,099,158

 
646,332

Montana Bakken
 
170,899

 
137,594

 
30,059

 
17,601

 
200,958

 
155,195

Red River units
 
158,967

 
139,418

 
26,719

 
13,124

 
185,686

 
152,542

Other
 
102,542

 
66,399

 
94,454

 
68,597

 
196,996

 
134,996

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
230,799

 
133,756

 
260,257

 
143,116

 
491,056

 
276,872

STACK
 
211,836

 
118,563

 
177,563

 
93,846

 
389,399

 
212,409

Other
 
67,734

 
32,928

 
71,250

 
33,067

 
138,984

 
65,995

East Region
 
449

 
404

 
161,935

 
138,799

 
162,384

 
139,203

Total
 
1,894,871

 
1,185,106

 
969,750

 
598,438

 
2,864,621

 
1,783,544


The following table sets forth the number of gross and net undeveloped acres as of December 31, 2017 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. 
 
 
2018
 
2019
 
2020
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
20,557

 
12,742

 
2,890

 
1,544

 
29,318

 
20,170

Montana Bakken
 
14,713

 
9,489

 
400

 
400

 

 

Red River units
 
5,617

 
3,318

 
2,879

 
1,365

 

 

Other
 
9,264

 
5,849

 
20,097

 
13,877

 
4,520

 
1,795

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
75,650

 
41,718

 
68,307

 
37,774

 
51,635

 
31,767

STACK
 
40,196

 
22,346

 
72,528

 
38,450

 
31,777

 
17,782

Other
 
1,840

 
504

 
28,258

 
12,251

 
23,513

 
11,986

East Region
 
6,947

 
6,292

 
55,347

 
40,336

 
11,728

 
10,164

Total
 
174,784

 
102,258

 
250,706

 
145,997

 
152,491

 
93,664



12



Drilling Activity
During the three years ended December 31, 2017, we drilled and completed exploratory and development wells as set forth in the table below:
 
 
2017
 
2016
 
2015
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
34

 
9.0

 
39

 
11.4

 
28

 
19.8

Natural gas
 
9

 
3.1

 
15

 
4.2

 
19

 
1.4

Dry holes
 

 

 

 

 
1

 
1.0

Total exploratory wells
 
43

 
12.1

 
54

 
15.6

 
48

 
22.2

Development wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
474

 
175.4

 
245

 
54.7

 
707

 
215.5

Natural gas
 
91

 
26.8

 
66

 
21.6

 
142

 
32.8

Dry holes
 

 

 

 

 

 

Total development wells
 
565

 
202.2

 
311

 
76.3

 
849

 
248.3

Total wells
 
608

 
214.3

 
365

 
91.9

 
897

 
270.5

As of December 31, 2017, there were 475 gross (179 net) operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.

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 2018 in our key operating areas. Our 2018 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 2018 budgeted capital expenditures by operating area.
 
 
2018 Plan
 
 
Gross wells (1)
 
Net wells (1)
 
Capital expenditures 
(in millions) (2)
 
 
North Region:
 
 
 
 
 
 
Bakken
 
415

 
143

 
$
1,193

South Region:
 
 
 
 
 
 
SCOOP
 
160

 
44

 
465

STACK and Other
 
181

 
38

 
330

Total exploration and development drilling
 
756

 
225

 
$
1,988

Land
 
 
 
 
 
132

Capital facilities, workovers and other corporate assets
 
 
 
 
 
168

Seismic
 
 
 
 
 
12

Total 2018 capital budget, excluding acquisitions
 
 
 
 
 
$
2,300

(1) Represents operated and non-operated wells expected to have first production in 2018.
(2) Represents total capital expenditures for operated and non-operated wells expected to have first production in 2018 and wells spud that will be in the process of drilling, completing or waiting on completion as of year-end 2018.

13



North Region
Our properties in the North region represented 50% of our total proved reserves as of December 31, 2017 and 61% of our average daily Boe production for the fourth quarter of 2017. Our average daily production from such properties was 175,563 Boe per day for the fourth quarter of 2017, an increase of 48% from the comparable 2016 period due to increased drilling and completion activities in 2017. Our principal producing properties in the North region are primarily located in the Bakken field.
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, 2017, we controlled one of the largest leasehold positions in the Bakken with approximately 1.3 million gross (801,500 net) acres under lease.
Our total Bakken production averaged 165,598 Boe per day for the fourth quarter of 2017, up 58% from the 2016 fourth quarter. For the year ended December 31, 2017, our average daily Bakken production increased 12% over 2016. We increased our drilling and well completion activities in the Bakken in 2017, particularly in the second half of the year, in response to stabilization and improvement in crude oil prices. In 2017, we participated in the drilling and completion of 370 gross (145 net) wells in the Bakken compared to 192 gross (38 net) wells completed in 2016. Our 2017 activities in the Bakken focused on development of de-risked, higher rate-of-return areas in core parts of North Dakota and the testing of various optimized completion methods aimed at improving crude oil recoveries and rates of return.
Our Bakken properties represented 48% of our total proved reserves at December 31, 2017 and 58% of our average daily Boe production for the 2017 fourth quarter. Our total proved Bakken field reserves as of December 31, 2017 were 636 MMBoe, an increase of 7% compared to December 31, 2016 due to reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,252 gross (656 net) wells as of December 31, 2017.
In response to the stabilization and improvement in crude oil prices in late 2017 and early 2018 we plan to increase our activities in North Dakota Bakken in 2018 relative to 2017. In 2018, we plan to invest approximately $1.19 billion in the play, which includes $413 million for the completion and initiation of production on operated Bakken wells that were drilled but not completed as of year-end 2017. We plan to operate, on average, six rigs in North Dakota Bakken throughout 2018, an increase from four rigs as of December 31, 2017. Additionally, we plan to use, on average, six to seven well completion crews in North Dakota Bakken throughout 2018, consistent with our current activity levels. Our 2018 drilling and completion activities will focus on core parts of North Dakota Bakken that provide opportunities to improve capital efficiency, reduce finding and development costs, and improve recoveries and rates of return.
South Region
Our properties in the South region represented 50% of our total proved reserves as of December 31, 2017 and 39% of our average daily Boe production for the fourth quarter of 2017. For the 2017 fourth quarter, our average daily production from such properties was 111,422 Boe per day, an increase of 22% from the comparable period in 2016. Our principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.
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, 2017, we controlled one of the largest leasehold positions in SCOOP with approximately 491,100 gross (276,900 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 with discoveries of the SCOOP Springer and Sycamore formations, which are located directly above the Woodford formation. Located in the heart of our SCOOP acreage, our Springer and Sycamore positions supplement our Woodford leasehold and expand our resource potential and inventory in the play. 

We engaged in limited drilling and completion activities in SCOOP in 2017, choosing instead to allocate capital to other areas that offered more advantageous opportunities and rates of return. Our 2017 activities in SCOOP focused on continued vertical and horizontal expansion of the productive extent and hydrocarbon content of the play and working to determine optimum well spacing, well patterns, and completion methods for future development.

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SCOOP represented 37% of our total proved reserves as of December 31, 2017 and 22% of our average daily Boe production for the fourth quarter of 2017. Production in SCOOP averaged 62,242 Boe per day during the fourth quarter of 2017, down 2% compared to the 2016 fourth quarter. For the year ended December 31, 2017, average daily production in SCOOP decreased 7% compared to 2016, reflecting natural declines in production and limited drilling and completion activities in 2017. We participated in the drilling and completion of 77 gross (20 net) wells in SCOOP during 2017 compared to 72 gross (28 net) wells in 2016. Proved reserves in SCOOP totaled 492 MMBoe as of December 31, 2017, an increase of 4% compared to December 31, 2016 due to reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017. Our inventory of proved undeveloped drilling locations in SCOOP totaled 336 gross (230 net) wells as of December 31, 2017.
In 2018, we plan to invest approximately $465 million to drill, complete and initiate production on 160 gross (44 net) operated and non-operated wells in the SCOOP play. We plan to average approximately seven operated rigs and one completion crew in SCOOP throughout 2018, an increase from five rigs as of December 31, 2017. Our 2018 drilling program will continue to focus on expanding the known productive extent of the SCOOP Woodford, Springer and Sycamore formations, 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 improving rates of return.
STACK
STACK is a significant 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, 2017, we controlled one of the largest leasehold positions in STACK with approximately 389,400 gross (212,400 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.
Building on early success achieved from our initial STACK drilling activities in mid-2015, we significantly increased our leasing and drilling activities in the play in 2016 and 2017. Our 2017 activities focused on pilot density drilling to expand our understanding of the productive extent and hydrocarbon content of the play and to help determine optimum well spacing, well patterns, and completion methods for future development.
Through our 2016 and 2017 activities in STACK, we have successfully tested productive zones in the play, applied optimized 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 future development of our STACK acreage, we continue to increase our water recycling and distribution capabilities in the play. Additionally, we continue to increase our access to gathering and takeaway capacity to handle crude oil and natural gas production expected from future development of the play.
Our STACK properties represented 13% of our total proved reserves as of December 31, 2017 and 17% of our average daily Boe production for the fourth quarter of 2017. Production in STACK increased to an average rate of 47,914 Boe per day during the fourth quarter of 2017, up 96% over the 2016 fourth quarter due to additional drilling and completion activity resulting from our drilling program. For the year ended December 31, 2017, average daily production in STACK grew 113% over 2016. We participated in the drilling and completion of 160 gross (49 net) wells in STACK during 2017 compared to 97 gross (26 net) wells in 2016. Proved reserves increased 4% year-over-year to 167 MMBoe as of December 31, 2017 due to reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017. Our inventory of proved undeveloped drilling locations in STACK totaled 195 gross (90 net) wells as of December 31, 2017.
In 2018, we plan to invest approximately $317 million to drill, complete and initiate production on 180 gross (37 net) operated and non-operated wells in STACK. We plan to average approximately eight operated rigs in STACK throughout 2018 compared to nine rigs as of December 31, 2017. Additionally, we plan to use, on average, three completion crews in STACK throughout 2018 compared to five crews as of December 31, 2017. Our 2018 activities will focus on delineating and de-risking our acreage, expanding the known productive extent of the play through the completion of new density test projects, monitoring production from optimized completions, and continued refinement of our geologic and economic models in the area.

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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, 2017, 2016 and 2015 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2017 (North Dakota Bakken and SCOOP). Information for the STACK field is also presented.  
 
 
Year ended December 31,
 
 
2017
 
2016
 
2015
Net production volumes:
 
 
 
 
 
 
Crude oil (MBbls)
 
 
 
 
 
 
North Dakota Bakken
 
35,964

 
31,723

 
37,539

SCOOP
 
5,726

 
6,807

 
7,198

STACK
 
3,166

 
1,552

 
245

Total Company
 
50,536

 
46,850

 
53,517

Natural gas (MMcf)
 
 
 
 
 
 
North Dakota Bakken
 
59,232

 
50,532

 
47,425

SCOOP
 
98,563

 
102,032

 
91,687

STACK
 
60,325

 
27,983

 
10,704

Total Company
 
228,159

 
195,240

 
164,454

Crude oil equivalents (MBoe)
 
 
 
 
 
 
North Dakota Bakken
 
45,836

 
40,145

 
45,444

SCOOP
 
22,153

 
23,813

 
22,479

STACK
 
13,220

 
6,216

 
2,029

Total Company
 
88,562

 
79,390

 
80,926

Average sales prices:
 
 
 
 
 
 
Crude oil ($/Bbl)
 
 
 
 
 
 
North Dakota Bakken
 
$
45.21

 
$
34.33

 
$
39.76

SCOOP
 
47.96

 
38.87

 
43.98

STACK
 
49.68

 
41.95

 
41.23

Total Company
 
45.70

 
35.51

 
40.50

Natural gas ($/Mcf)
 
 
 
 
 
 
North Dakota Bakken
 
$
2.97

 
$
1.05

 
$
2.34

SCOOP
 
3.26

 
2.24

 
2.39

STACK
 
2.43

 
1.87

 
2.06

Total Company
 
2.93

 
1.87

 
2.31

Crude oil equivalents ($/Boe)
 
 
 
 
 
 
North Dakota Bakken
 
$
39.32

 
$
28.45

 
$
35.29

SCOOP
 
26.93

 
20.71

 
23.81

STACK
 
22.89

 
18.88

 
15.87

Total Company
 
33.65

 
25.55

 
31.48

Average costs per Boe:
 
 
 
 
 
 
Production expenses ($/Boe)
 
 
 
 
 
 
North Dakota Bakken
 
$
4.40

 
$
4.59

 
$
4.79

SCOOP
 
1.01

 
1.13

 
1.10

STACK
 
1.22

 
1.00

 
3.52

Total Company
 
3.66

 
3.65

 
4.30

Production taxes ($/Boe)
 
$
2.35

 
$
1.79

 
$
2.47

General and administrative expenses ($/Boe)
 
$
2.16

 
$
2.14

 
$
2.34

DD&A expense ($/Boe)
 
$
18.89

 
$
21.54

 
$
21.57


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The following table sets forth information regarding our average daily production by region for the fourth quarter of 2017: 
 
 
Fourth Quarter 2017 Daily Production
 
 
Crude Oil
(Bbls per day)
 
Natural Gas
(Mcf per day)
 
Total
(Boe per day)
North Region:
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
North Dakota Bakken
 
124,811

 
202,975

 
158,640

Montana Bakken
 
5,497

 
8,761

 
6,958

Red River units
 
 
 
 
 
 
Cedar Hills
 
6,830

 
1,154

 
7,022

Other Red River units
 
2,073

 
2,410

 
2,475

Other
 
82

 
2,318

 
468

South Region:
 
 
 
 
 
 
SCOOP
 
14,551

 
286,148

 
62,242

STACK
 
13,788

 
204,754

 
47,914

Other
 
434

 
4,998

 
1,266

Total
 
168,066

 
713,518

 
286,985

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, 2017. 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
 
4,083

 
1,313

 

 

 
4,083

 
1,313

Montana Bakken
 
401

 
263

 

 

 
401

 
263

Red River units
 
 
 
 
 
 
 
 
 
 
 


Cedar Hills
 
135

 
130

 

 

 
135

 
130

Other Red River units
 
131

 
117

 

 

 
131

 
117

Other
 
8

 
4

 
18

 
4

 
26

 
8

South Region:
 
 
 
 
 
 
 
 
 
 
 

SCOOP
 
248

 
145

 
372

 
115

 
620

 
260

STACK
 
172

 
62

 
282

 
98

 
454

 
160

Other
 
139

 
110

 
167

 
65

 
306

 
175

Total
 
5,317

 
2,144

 
839

 
282

 
6,156

 
2,426

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 and production databases to determine fee mineral ownership and availability. Title, lease forms, and final terms are reviewed and approved by Company landmen prior to consummation.
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 physical well site inspections, and examine the seller’s internal records (land, legal, operational, production, environmental, well, marketing and accounting) 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.

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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 approve commencement of 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 at least 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 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 operated crude oil production is sold to either crude oil refining companies or midstream marketing companies at major market centers. Other operated production not sold at major market centers is sold at the lease. In the Bakken, SCOOP and STACK areas we have significant volumes of production directly connected to pipeline gathering systems, with the remaining balance of production being primarily transported by truck. Additionally in the Bakken, a portion of our production is sold to counterparties that are connected to 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. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.
The majority of our operated 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 share of natural gas production from non-operated properties is generally marketed at the discretion of the operators.
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.
For the year ended December 31, 2017, sales to BP p.l.c. and affiliates and Phillips 66 and affiliates accounted for approximately 11% and 11%, respectively, of our total crude oil and natural gas revenues. No other purchaser accounted for more than 10% of our total crude oil and natural gas revenues for 2017. The loss of any single purchaser will 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.

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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, as amended from time to time, 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. Beginning in the 1970s, the United States 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 some 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, 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 described in the pipelines’ published tariffs. 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 pipeline and rail transportation facilities owned and operated by third parties. Approximately 6% of such production was shipped by rail in December 2017, 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 U.S. Occupational Safety and Health Administration ("OSHA"), 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; issuing rules 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. 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 published 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 as early as January 1, 2018. However, in December 2017 PHMSA announced it would initiate a rulemaking to rescind the May 2015 rule's requirements regarding electronically controlled pneumatic brakes. 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 to expand the applicability of comprehensive oil spill response plans so that any railroad transporting 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. Issuance of the final rule remains pending.
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 do not expect such regulations will affect us in a materially different way than similarly situated competitors.
In June 2016 the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act (“PIPES Act”) was signed into law. The PIPES Act extends PHMSA’s safety authority through 2019 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. PHMSA published a final rule in January 2017 expanding integrity management and reporting requirements for certain hazardous liquid pipelines and gathering lines; however, implementation of the final rule was stayed following the change in U.S. Presidential Administrations. The final rule is expected to be published in the federal register during the first quarter of 2018. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.
Pipeline regulations exist at the state level as well. 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 and transported on railcars. The rules became effective in April 2015 and 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. These rules do not 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 potential 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. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers on a comparable basis, 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 where 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. Additionally, certain aspects of the Dodd-Frank Act were repealed by the U.S. Congress in 2017.
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 current or future 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 may adopt or implement 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 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 or otherwise limit our ability to manage our financial and commercial risks related to fluctuations in commodity prices. Additional effects of the 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 contribute to the formation of price indices. The FERC also requires market participants to indicate whether they report prices

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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 prohibiting, 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 brought before the U.S. Congress, the FERC and the courts from time to time. 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.
In March 2017, President Donald Trump issued an Executive Order titled “Promoting Energy Independence and Economic Growth” (the "March 2017 Executive Order") which states it is in the national interest of the United States to promote clean and safe development of energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation. The March 2017 Executive Order requires, among other things, the executive department and agencies to review existing regulations that potentially burden the development or use of domestically produced energy resources (with particular attention to crude oil, natural gas, coal, and nuclear energy) and suspend, revise, or rescind those regulations that unduly burden the development of such resources beyond the degree necessary to protect the public interest or otherwise comply with the law. In response to the March 2017 Executive Order, certain energy and climate-related regulations proposed or enacted under previous presidential administrations have been, or are in the process of being, reviewed, suspended, revised, or rescinded, some of which are described further below. Numerous regulations impacting the crude oil and natural gas industry are not expected to be impacted by the March 2017 Executive Order and will continue to be in effect. Additionally, undoing previously existing environmental regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further regulation of our industry may stall at the federal level under the March 2017 Executive Order, certain states have pursued additional regulation of our operations and other states may do so as well.
Environmental laws, rules and regulations. Some of the existing environmental laws, rules and regulations we are subject to include: (i) regulations by the U.S. Environmental Protection Agency (“EPA”) and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the federal Comprehensive Environmental Response,

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Compensation, and Liability Act and analogous state laws that may require the removal of previously disposed hazardous substances (including hazardous substances 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 federal Clean Air Act and comparable state and local requirements, which establish pollution control requirements for air emissions from our operations; (v) the federal 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, also known as 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 federal Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of solid and hazardous wastes, and comparable state statutes; (viii) the federal Safe Drinking Water Act ("SDWA") 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 having the potential to significantly impact the environment; (x) the federal Endangered Species Act and comparable state statutes, which afford protections to certain plant and animal species; (xi) the federal Migratory Bird Treaty Act, which imposes certain restrictions for the protection of migratory birds; (xii) the federal Bald and Golden Eagle Protection Act, which imposes certain restrictions for the protection of bald and golden eagles; (xiii) the federal 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 occurrence of delays in the permitting or performance of projects, 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 and secondary standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 35% of the U.S. counties, including all of the counties in North Dakota and all of the counties except for Bryan County in Oklahoma, as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue attainment or nonattainment designations for the remaining areas of the U.S. not addressed under the November 2017 rule in the first half of 2018. Additionally, 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”) pre-construction and Title V operating permit reviews for certain large stationary sources. Moreover, the EPA’s source determination rule 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 the EPA as a single, large stationary source and, therefore, subject to PSD and/or Title V.  Regulations 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”) 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 that materially differs from our similarly situated competitors.

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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.
However, in June 2017, the EPA proposed to stay certain portions of the NSPS Quad Oa rules described above for a period of two years while the rules are reconsidered in response to President Trump’s March 2017 Executive Order to reduce the burden of federal regulations that may hinder economic growth and energy development. The EPA has not yet published a final rule issuing the stay, and, as a result, the Quad Oa rules are currently in effect but future implementation of the Quad Oa rules is uncertain at this time. As part of its reconsideration, the EPA may issue revised rules, the timing and impact of which is uncertain.
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, in response to President Trump’s March 2017 Executive Order, in December 2017 the BLM announced it was temporarily suspending or delaying certain requirements contained in its Venting and Flaring Rule until January 2019. That suspension is now being challenged in court and future implementation and impact of the rule remains uncertain. While additional federal regulation with respect to methane emissions appears unlikely in the near future, states may nevertheless pursue rules or enforcement actions designed to reduce methane emissions. To the extent new methane emission regulationswhether it is the BLM Venting and Flaring Rule, a prospective EPA rule targeting methane emissions from existing sources, or a state agencyimpose 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, originally 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. In June 2017, President Trump announced the United States will withdraw from and cease implementation of the Paris climate agreement, but indicated the U.S. may re-engage in the agreement if more favorable terms can be re-negotiated. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris climate agreement. The exit process provided for under the Paris agreement could take up to four years. The United States’ adherence to the exit process is uncertain and the terms on which the United States may reenter the Paris agreement or a separately negotiated agreement are unclear. Although the U.S. has ceased its participation in the Paris agreement, the agreement nonetheless may result in increased political 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 enacted 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, though such a tax appears unlikely at this time. Although it is not possible 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 and lower the value of our reserves. 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 the EPA against an operator resulted in a consent decree between the parties

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requiring 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.
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.
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 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 amounts. 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 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 88% beginning November 1, 2018 and 91% beginning November 1, 2020. Ongoing 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, 2017, we delivered approximately 90% of our operated natural gas production in the North Dakota Bakken field to market, flaring approximately 10% compared to 9% in 2016 and 13% in 2015. According to data published by the NDIC, our industry as a whole flared approximately 12% of produced natural gas volumes in the North Dakota Bakken field during 2017. 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. We have taken numerous actions to reduce flaring from our operated well sites, such as coordinating our well completion operations to coincide with well connections to gathering systems in order to minimize flaring; however, we 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 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. For example, over the past year insufficient takeaway capacity in North Dakota has created challenges for all operators and contributed to an increase in volumes of flared gas. Increased emissions from a multi-well pad facility or centralized production facilities due to flaring could require us to adhere to PSD or Title V permit requirements. We have filed several permits to construct major sources (i.e., facilities from which emissions of a criteria pollutant (e.g., carbon monoxide or volatile organic compounds) are expected to exceed 100 tons per year) relating to facilities where takeaway capacity is currently constrained and creating a potential to emit in excess of 100 tons per year.
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.

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Hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppant 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, the 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.
In December 2016 the EPA published a final study of the potential impacts of hydraulic fracturing activities on water resources. In its 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 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. In December 2017, the BLM formally rescinded its March 2015 hydraulic fracturing rules, citing unjustified administrative burdens and compliance costs arising from a reassessment performed in response to President Trump's March 2017 Executive Order to reduce the burden of federal regulations that may hinder economic growth and energy development. In January 2018, litigation challenging the BLM's rescission of the March 2015 final rules was brought in federal court. As of December 31, 2017, we held approximately 65,500 net undeveloped acres on federal land, representing approximately 11% of our total net undeveloped acres.
At the state level, several 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 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”) has promulgated guidance for operators of crude oil and gas wells in certain seismically-active areas of the SCOOP and STACK plays in Oklahoma. The OCC's guidance provides for seismic monitoring and for implementation of mitigation procedures, which may include a suspension of operations in the event of concurrent seismic events within a particular radius of operations of a magnitude exceeding 2.5 on the Richter scale. The OCC may update this guidance to impose a larger monitoring area and more stringent requirements for notification and suspension of operations. If seismic events exceeding the OCC guidance thresholds 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

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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 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 states in which we operate are considering additional requirements related to seismicity. For example, the 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 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 recent years we have increased our operation and use of water recycling and distribution facilities in Oklahoma 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 and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulation under Title III of the federal superfund Amendment and Reauthorization Act 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, 2017, we employed 1,127 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, Corporate Governance Guidelines, 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,

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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 2017 the NYMEX West Texas Intermediate (“WTI”) crude oil and Henry Hub natural gas spot prices ranged from approximately $42 to $60 per barrel and $2.45 to $3.70 per MMBtu, respectively. Commodity prices may remain volatile and unpredictable in 2018 and beyond.
We have hedged the majority of our forecasted 2018 natural gas production. Our future crude oil production is currently unhedged and directly exposed to continued volatility in 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 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/or 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/or natural gas properties. Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating

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action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase the borrowing costs under our revolving credit facility, and 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 may 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 64% of our crude oil and natural gas revenues for the year ended December 31, 2017. Approximately 48% of our estimated proved reserves were located in the Bakken as of December 31, 2017. Additionally, in recent years we have significantly expanded our operations in Oklahoma with our increased activity in the SCOOP and STACK plays. Our properties in Oklahoma comprised approximately 41% 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, 2017. Approximately 50% of our estimated proved reserves were located in Oklahoma as of December 31, 2017.
Because of this concentration in limited geographic areas, the success and profitability of our operations may be disproportionately exposed to regional factors compared to competitors having 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, oilfield 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 and services 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, labor difficulties, civil disturbances, public protests, or terrorist attacks. 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, resulting in 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 and asset dispositions 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.
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 $2.30 billion for capital expenditures in 2018 (excluding acquisitions which are not budgeted) of which $1.99 billion is allocated for exploration and development drilling. We may adjust our 2018 capital spending plans upward or downward 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 recent years non-strategic asset

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dispositions have provided a source of cash flow for use in reducing 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 and completion results, the availability of drilling and completion rigs and other services and equipment, the availability of transportation and processing 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;
our ability to dispose of assets or enter into joint development arrangements on satisfactory terms; 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. Currently, we have a revolving credit facility with lender commitments totaling $2.75 billion that matures in May 2019. 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. Our lenders could decline to increase their commitments based on our financial condition, the financial condition of our industry or the economy as a whole or for other reasons beyond our control. 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 operating cash flows are insufficient and we are unable to access funding or execute capital transactions 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 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 or joint development arrangements. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. 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.
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; unintended interference of completion activities performed by us or by third parties with nearby operated or non-operated wells being drilled, completed, or producing; and failure of our optimized completion techniques to yield expected levels of production.
Further, many factors may curtail, delay or cancel scheduled drilling projects, including but not limited to:

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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.
Any of the above events 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 likely 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, standardized measure of discounted future net cash flows, and PV-10 as of December 31, 2017.
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 will likely 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 2017, 89 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.
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, 2017, average prices used to calculate our estimated proved reserves were $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas ($47.03 per Bbl for crude oil and $3.00 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

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natural gas first-day-of-the-month commodity prices for January 1, 2018 and February 1, 2018 averaged $63.11 per barrel and $3.40 per MMBtu, respectively. 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.
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.

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Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our cash flows and results of operations.
Unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.
The unavailability or high cost of 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. The demand for qualified and experienced oilfield service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages.
Certain drilling and completion costs and costs of oilfield services, equipment, and materials decreased in recent years as service providers reduced their costs in response to reduced demand arising from low crude oil prices. However, inflationary pressures returned in 2017 and are expected to continue in 2018 in conjunction with the stabilization and improvement in crude oil prices in recent months.
As a result of the low commodity price environment in recent years, the number of providers of services, equipment, and materials decreased in the regions where we operate. Further, increased industry drilling and completion activities in recent months prompted by improvement in crude oil prices may cause shortages or higher costs of services, equipment, and materials. Such shortages or higher 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, all of 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 and explosions;
ruptures of pipelines or storage facilities;
loss of product or property damage occurring as a result of transfer to a rail car or train derailments;
personal injuries and death;
adverse weather conditions and natural disasters; and
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
injury or loss of life;
damage to or destruction of property, natural resources and equipment;

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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 or for other reasons. 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 and processing 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 57% of our total net undeveloped acreage at December 31, 2017. At that date, we had leases representing 102,258 net acres expiring in 2018, 145,997 net acres expiring in 2019, and 93,664 net acres expiring in 2020. 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, 2017, approximately 55% 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, 2017 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $6.4 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

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proved undeveloped reserves not developed within this five-year time frame. Such removals have occurred in the past and will likely occur in the future. A removal of such reserves could adversely affect our operations. In 2017, 89 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.
Our business depends on crude oil and natural gas transportation, processing, and refining facilities, most of which are owned by third parties.
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, the delay or discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. 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 and acreage lease terminations could result if production is shut-in for a prolonged period.
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 fulfills transportation commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings absent sufficient cash flows.
Our operated crude oil and natural gas production is transported to market centers primarily using pipeline and rail transportation facilities owned and operated by third parties. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of regulations impacting the transportation of crude oil and natural gas. We do not currently own or operate transportation infrastructure; however, compliance with regulations that impact the transportation of crude oil or natural gas could increase our costs of doing business and limit our ability to transport and sell our production 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. Rules and regulations have been developed in Oklahoma to address these concerns by limiting or eliminating the ability to use disposal wells in certain locations or increasing 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.

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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, limitations in our ability to develop and produce reserves, and reduced 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”) pre-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. For further discussion of Title V and PSD concerns, see Part I, Item 1. Business–Regulation of the Crude Oil and Natural Gas Industry–Environmental regulation–Air emissions and climate change. Also see Part I, Item 1. Business–Regulation of the Crude Oil and Natural Gas Industry–Environmental regulation–Environmental protection and natural gas flaring. 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. Regulations 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.
Certain previously existing climate-related regulations, such as those related to the control of methane emissions, have been, or are in the process of being, reviewed, suspended, revised, or rescinded in response to President Trump's March 2017 Executive Order. Undoing previously existing regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further climate-related regulation of our industry may stall at the federal level under the March 2017 Executive Order, certain states have pursued additional regulation of our operations related to the emission of greenhouse gases and other states may do so as well. For instance, several state and regional greenhouse gas cap and trade

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programs have emerged, while other states have imposed limitations on emissions of methane through equipment control and leak detection and repair requirements.
The implementation of, and compliance with, 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, install new equipment to reduce emissions of greenhouse gases associated with our operations, or limit our ability to develop and produce our reserves. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the crude oil and natural gas we produce, which could lower the value of our reserves and 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, additional operating restrictions or delays, and an inability to develop existing reserves or 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 or other proppant 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 regulatory initiatives have emerged that seek to 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.
States in which we operate have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure, and well construction and reclamation 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 changes to existing laws or regulations or changes in interpretations of laws 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 interpretations 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, modification of equipment utilized in our operations, 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, interpretations 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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Certain aspects of the newly enacted federal income tax reform legislation in the United States could adversely affect us.
On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law by President Trump. The Tax Reform Act represents the most significant tax policy change in the United States since 1986 and includes, among others, the following key changes to federal tax law:
Reduces the corporate tax rate from 35% to 21% and eliminates the corporate alternative minimum tax;
Limits the tax deduction for certain net operating loss (NOL) carryforwards to 80% of taxable income for a taxable year, allows NOLs generated in years after December 31, 2017 to be carried forward indefinitely, and repeals NOL carrybacks;
Limits the tax deduction for business interest expense to 30% of adjusted taxable income for a taxable year;
Allows businesses to immediately expense the cost of new investments in certain qualified depreciable assets;
Creates a territorial tax system rather than a worldwide system, which generally allows companies to repatriate future foreign source earnings without incurring additional U.S. taxes;
Subjects foreign earnings on which U.S. income tax is currently deferred to a one-time transition tax; and
Eliminates or reduces certain deductions, exclusions, and credits and adds other provisions that broaden the tax base.
Changes arising from the Tax Reform Act, which are subject to a number of important qualifications and exceptions, generally become effective for tax years beginning after December 31, 2017. Certain of the changes are permanent, while others expire at specified dates. The Tax Reform Act's provisions could have state and local tax implications. While some states automatically adopt federal tax law changes, others conform their laws with federal law on specific dates. States also may choose to decouple from the new federal tax provisions and continue to apply previous law.
Apart from the future benefits to be realized from the reduction in the corporate income tax rate from 35% to 21%, the overall long-term impact of other aspects of the Tax Reform Act is uncertain, and our business, financial condition, results of operations and cash flows could be adversely affected by certain new provisions, particularly the limitations on the tax deductibility of business interest expense and NOLs. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Legislative and Regulatory Developments–Tax Reform Legislation for a forward-looking discussion of the potential impact of the Tax Reform Act.
In previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and gas exploration and production companies. Such proposed changes have included: (i) a repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of deductions for intangible drilling and exploration and development costs; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. These tax deductions currently utilized within our industry are not impacted by the Tax Reform Act. However, no prediction can be made as to whether any legislative changes will be proposed or enacted in the future that could eliminate or defer these or other tax deductions utilized within our industry.
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, securing long-term transportation and processing capacity, 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, securing long-term transportation and processing capacity, 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.
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, induced seismicity, and greenhouse gas emissions may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and

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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.
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.
Severe weather events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Severe weather events and natural disasters such as hurricanes, 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 or the operations of third party service providers. Such events may result in significant destruction of infrastructure, businesses, and homes and could disrupt the distribution and supply of crude oil and natural gas products in the impacted region. The consequences of such events may include the evacuation of personnel; damage to and disruption of drilling rigs or transportation, processing, storage and refining facilities; the shut-in of production resulting from an inability to transport crude oil or natural gas products to market centers and other factors; 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 or cash flows.
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.
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.

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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, 2017, non-operated properties represented 18% of our estimated proved developed reserves, 6% of our estimated proved undeveloped reserves, and 11% 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 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 contains restrictive covenants that may 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 also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (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, 2017, our consolidated net debt to total capitalization ratio, as defined, was 0.51 to 1.00. Our total debt would need to independently increase by approximately $5.2 billion above the existing level at December 31, 2017 (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 $2.8 billion below the existing level at December 31, 2017 (excluding the after-tax impact of any non-cash impairment charges) to reach the maximum covenant ratio.
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 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 or senior note indentures may be impacted by changes in economic or business conditions, results of operations, or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, 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.
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
Our business and industry 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:

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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 transportation, processing, storage or refining facilities 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.
Increases in interest rates could adversely affect our business.
The U.S. Federal Reserve increased the benchmark federal funds interest rate on three separate occasions in 2017 and is forecasting additional increases in 2018 and 2019. Our business and operating results can be adversely affected by increases in interest rates, the availability, terms of and cost of capital, or downgrades or other negative rating actions with respect to our credit rating. These factors could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. 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 ($672 million in receivables at December 31, 2017); our joint interest and other receivables ($427 million at December 31, 2017); and counterparty credit risk associated with our derivative instrument receivables ($3 million at December 31, 2017).
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 two largest purchasers of our crude oil and natural gas during the year ended December 31, 2017 accounted for approximately 11% and 11%, respectively, 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 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, 2017. 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:

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production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contractual obligations; or
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, our derivative arrangements limit the benefit we would receive from increases in commodity prices. Our decision on the quantity and price at which we choose to hedge our future production, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to hedge future production if the pricing environment for certain time periods is deemed to be unfavorable. 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.
We have hedged the majority of our forecasted 2018 natural gas production. Our future crude oil production is currently unhedged and directly exposed to continued volatility in market prices, whether favorable or unfavorable.
Our Chairman and Chief Executive Officer 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, 2017, Harold G. Hamm, our Chairman and Chief Executive Officer, 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 may not coincide with the interests of other holders of our common stock.
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, divestitures, and joint development arrangements.
As part of our business strategy, we have made and will likely continue to make acquisitions of oil and gas properties, divest of non-strategic assets, and enter into joint development arrangements. Suitable acquisition properties, buyers of our non-strategic assets, or joint development counterparties may not be available on terms and conditions we find acceptable or not at all.
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 acquisition 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

44



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.
In addition, from time to time we may sell or otherwise dispose of certain non-strategic assets as a result of an evaluation of our asset portfolio or to provide cash flow for use in reducing debt and enhancing liquidity. Such divestitures have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets, and potential post-closing adjustments and claims for indemnification. Additionally, volatility and unpredictability in commodity prices may result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to closing.
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 infrastructure we rely on 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.



45



Item 1B.    Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2017.
 
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.
We have received Notices of Violation from the North Dakota Department of Health (“NDDH”) alleging violations of the state’s air quality and water pollution control laws and rules.  We exchanged information and engaged in discussions with NDDH aimed at resolving the allegations and anticipate further discussions and exchanges.  Resolution of the allegations may result in monetary sanctions of more than $100,000.

Item 4.
Mine Safety Disclosures
Not applicable.

46



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. 
 
 
2017
 
2016
 
 
Quarter Ended
 
Quarter Ended
 
 
March 31
 
June 30
 
September 30
 
December 31
 
March 31
 
June 30
 
September 30
 
December 31
High
 
$
53.57

 
$
47.87

 
$
40.03

 
$
53.55

 
$
31.90

 
$
46.01

 
$
52.78

 
$
60.30

Low
 
$
41.28

 
$
30.18

 
$
29.08

 
$
36.05

 
$
13.94

 
$
28.63

 
$
40.92

 
$
44.37

Cash Dividend
 

 

 

 

 

 

 

 

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. As of January 31, 2018, the number of record holders of our common stock was 1,146. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately 64,400. On January 31, 2018, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $55.53 per share.
The following table summarizes our purchases of our common stock during the quarter ended December 31, 2017:
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, 2017 to October 31, 2017
 
234

 
$
38.24

 

 

November 1, 2017 to November 30, 2017