Company Quick10K Filing
Quick10K
Continental Resources
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$48.89 377 $18,420
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-02-18 Earnings, Regulation FD, Exhibits
8-K 2019-02-13 Earnings, Exhibits
8-K 2019-02-12 Officers
8-K 2018-10-29 Earnings, Regulation FD, Exhibits
8-K 2018-08-07 Earnings, Regulation FD, Exhibits
8-K 2018-07-24 Earnings, Exhibits
8-K 2018-05-17 Shareholder Vote
8-K 2018-05-02 Earnings, Regulation FD, Exhibits
8-K 2018-04-09 Enter Agreement, Leave Agreement, Off-BS Arrangement, Exhibits
8-K 2018-03-26 Officers
8-K 2018-03-19 Officers
8-K 2018-02-21 Earnings, Regulation FD, Exhibits
8-K 2018-02-16 Other Events
8-K 2018-02-15 Earnings, Exhibits
SHOO Steven Madden 2,900
NFE New Fortress Energy LLC 1,860
CMCO Columbus McKinnon 940
HMTV Hemisphere Media Group 588
SRDX Surmodics 550
SFS Smart & Final Stores 412
SGC Superior Group of Companies 278
BWFG Bankwell Financial 234
NVTR Nuvectra 189
LZD Lazard Group 0
CLR 2018-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Note 1. Organization and Summary of Significant Accounting Policies
Note 2. Supplemental Cash Flow Information
Note 3. Net Property and Equipment
Note 4. Accrued Liabilities and Other
Note 5. Derivative Instruments
Note 6. Fair Value Measurements
Note 7. Long-Term Debt
Note 8. Revenues
Note 9. Income Taxes
Note 10. Lease Commitments
Note 11. Commitments and Contingencies
Note 12. Related Party Transactions
Note 13. Stock-Based Compensation
Note 14. Accumulated Other Comprehensive Income (Loss)
Note 15. Noncontrolling Interests
Note 16. Property Dispositions
Note 17. Crude Oil and Natural Gas Property Information
Note 18. Supplemental Crude Oil and Natural Gas Information (Unaudited)
Note 19. Quarterly Financial Data (Unaudited)
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
EX-21 clr201810k-ex21.htm
EX-23.1 clr201810k-ex23i.htm
EX-23.2 clr201810k-ex23ii.htm
EX-31.1 clr201810k-ex31i.htm
EX-31.2 clr201810k-ex31ii.htm
EX-32 clr201810k-ex32.htm
EX-99 clr201810k-ex99.htm

Continental Resources Earnings 2018-12-31

CLR 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 clr201810-k.htm 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, 2018
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 every Interactive Data File required to be submitted 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 such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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
 
¨  
  
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, 2018 was approximately $5.6 billion, based upon the closing price of $64.76 per share as reported by the New York Stock Exchange on such date.
376,014,925 shares of our $0.01 par value common stock were outstanding on January 31, 2019.

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 2019, 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 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.
“MBoe” One thousand Boe.
“Mcf” One thousand cubic feet of natural gas.

i



“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.
"Net crude oil and natural gas sales" Represents total crude oil and natural gas sales less total transportation expenses. Net crude oil and natural gas sales is a non-GAAP measure for 2018. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of such measure.
"Net sales price" Represents the average net wellhead sales price received by the Company for its crude oil or natural gas sales after deducting transportation expenses. Such amount is calculated by taking revenues less transportation expenses divided by sales volumes for a period, whether for crude oil or natural gas, as applicable. Net sales prices are non-GAAP measures for 2018. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of such measures.
“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.
“residue gas” Refers to gas that has been processed to remove natural gas liquids.

ii



“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.
“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.
“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 formed in 1967 engaged in the exploration, development, and production of crude oil and natural gas primarily in the North, South and East regions of the United States. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. 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 and STACK 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.
A substantial portion of our operations is located in the North region, with that region comprising 59% of our crude oil and natural gas production and 73% of our crude oil and natural gas revenues for the year ended December 31, 2018. The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. Approximately 55% of our proved reserves as of December 31, 2018 are located in the North region. Our operations in the South region continue to expand with our increased activity in the SCOOP and STACK plays and that region comprised 41% of our crude oil and natural gas production, 27% of our crude oil and natural gas revenues, and 45% of our proved reserves as of and for the year ended December 31, 2018.
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), pad/row development, 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, 2018, our proved reserves were 1,522 MMBoe, with proved developed reserves representing 675 MMBoe, or 44%, of our total proved reserves. The standardized measure of our discounted future net cash flows totaled $15.7 billion at December 31, 2018. For 2018, we generated crude oil and natural gas revenues of $4.68 billion and operating cash flows of $3.46 billion. Crude oil accounted for 56% of our total production and 81% of our crude oil and natural gas revenues for 2018. Our total production averaged 298,190 Boe per day for 2018, a 23% increase compared to 2017.
The table below summarizes our total proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, 2018, average daily production for the quarter ended December 31, 2018 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, 2018
 
Average daily
production for
fourth quarter
2018
(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
 
767,837

 
50.4
%
 
$
11,374

 
1,446

 
177,358

 
54.7
%
 
11.9

Montana Bakken
 
30,168

 
2.0
%
 
473

 
263

 
6,478

 
2.0
%
 
12.8

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
28,771

 
1.9
%
 
455

 
129

 
6,598

 
2.0
%
 
11.9

Other Red River units
 
3,661

 
0.2
%
 
55

 
114

 
2,446

 
0.8
%
 
4.1

Other
 
31

 
%
 
1

 
2

 
33

 
%
 
2.6

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
459,103

 
30.2
%
 
4,742

 
310

 
67,244

 
20.8
%
 
18.7

STACK
 
230,175

 
15.1
%
 
1,528

 
205

 
62,947

 
19.4
%
 
10.0

Other
 
2,619

 
0.2
%
 
22

 
120

 
897

 
0.3
%
 
8.0

Total
 
1,522,365

 
100.0
%
 
$
18,650

 
2,589

 
324,001

 
100.0
%
 
12.9

 
(1)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $3.0 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 2018 production into estimated proved reserve volumes as of December 31, 2018.
Business Environment and Outlook
Our industry is impacted by volatility and uncertainty in commodity prices. Crude oil prices showed significant signs of improvement throughout the majority of 2018, with West Texas Intermediate crude oil benchmark prices rising above $75 per barrel in June and again in October before decreasing more than 40% in the fourth quarter to an 18-month low of $44 per barrel at year-end 2018. Crude oil prices have since rebounded from year-end 2018 lows, but remain volatile and unpredictable. 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 2019, our primary business strategies will focus on:
Enhancing free cash flow generation and oil-weighted production growth;
Enhancing rates of return on capital employed through improvements in operating efficiencies, technical innovations, pad and row development, optimized completion methods, well productivity, and strategic mineral ownership;
Continuing to exercise disciplined capital spending to maintain financial flexibility and ample liquidity; and
Reducing outstanding debt using available operating cash flows, proceeds from asset dispositions, or joint development arrangements.
Our capital expenditures budget for 2019 is $2.6 billion compared to $2.8 billion spent in 2018, with the majority of our 2019 drilling and completion budget focusing on oil-weighted areas in North Dakota Bakken and SCOOP. Under the current commodity price environment, our planned capital expenditures for 2019 are expected to be funded entirely from operating cash flows. As we have done in the past, we may adjust our pace of drilling and development as 2019 market conditions evolve.
For 2019, we plan to operate an average of 25 drilling rigs and 9 completion crews for the year. We expect to spend approximately 41% of our 2019 capital expenditures budget on drilling and completion activities in the Bakken and 42% on drilling and completion activities in Oklahoma. The remaining 17% of our 2019 budget will target other capital expenditures

2



such as leasing and renewals, mineral acquisitions, work-overs, and facilities. See the section below titled Summary of Crude Oil and Natural Gas Properties and Projects for further discussion of our 2019 plans.
Our Business Strategy
Despite 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 free cash flow generation and oil-weighted production growth. We hold a portfolio of leasehold acreage, perpetually owned minerals, 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 oil-weighted production growth while generating cash flows in excess of operating and capital requirements, to harvest our 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 rates of return on capital employed through operating efficiencies, technical innovations, pad and row development, optimized completions, well productivity, and strategic mineral ownership. We continue to manage our business in the volatile commodity price environment by focusing on improving operating efficiencies and managing costs by exploiting technical innovations, pad and row development opportunities, and other means. 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 enhance operating efficiencies and economies of scale.
Additionally, we capitalize on our geologic knowledge and land expertise to strategically acquire minerals in areas of future growth, thereby allowing us to enhance cash flows and project economics through the alignment of mineral ownership with our drilling schedule. Our mineral ownership strategy serves as another avenue to enhance shareholder returns.
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 2018, we reduced our total debt by $585 million, or 9%, and had no outstanding borrowings on our credit facility at December 31, 2018. Additionally, we increased our cash on hand by $239 million during the year to $283 million at year-end 2018. We are actively targeting further debt reduction using available cash, operating cash flows, 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.
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 525,700 net undeveloped acres and 1.22 million net developed acres under lease as of December 31, 2018 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.
Expertise with pad and row development, 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 and row development strategies. 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.

3



Control Operations Over a Substantial Portion of Our Assets and Investments. As of December 31, 2018, we operated properties comprising 85% 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 and with operating in challenging commodity price environments. Our Chief Executive Officer, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 9 executive officers have an average of 39 years of oil and gas industry experience.
Financial Position and Liquidity. We have a credit facility with lender commitments totaling $1.5 billion that matures in April 2023. We had no outstanding borrowings on the facility at December 31, 2018 and continued to have no borrowings as of January 31, 2019. 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.


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 table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2018. Proved reserves attributable to noncontrolling interests are immaterial and are not separately presented herein. The standardized measure of our discounted future net cash flows totaled approximately $15.7 billion at December 31, 2018. Our reserve estimates as of December 31, 2018 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 98% of our PV-10 and 98% of our total proved reserves as of December 31, 2018. 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, 2018 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2018 through December 2018, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $65.56 per Bbl for crude oil and $3.10 per MMBtu for natural gas ($61.20 per Bbl for crude oil and $3.22 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
 
346,969

 
1,955,727

 
672,923

 
$
10,248.0

Proved developed non-producing
 
856

 
8,562

 
2,283

 
23.8

Proved undeveloped
 
409,271

 
2,627,325

 
847,159

 
8,378.5

Total proved reserves
 
757,096

 
4,591,614

 
1,522,365

 
$
18,650.3

Standardized Measure (1)
 
 
 
 
 
 
 
$
15,684.8

 
(1)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $3.0 billion. 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, 2018. 
 
 
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
 
237,195

 
588,212

 
335,232

 
300,126

 
794,883

 
432,606

Montana Bakken
 
20,523

 
40,874

 
27,336

 
2,312

 
3,119

 
2,832

Red River units
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Hills
 
28,004

 
4,606

 
28,771

 

 

 

Other Red River units
 
3,659

 
13

 
3,661

 

 

 

Other
 
30

 
7

 
31

 

 

 

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
45,517

 
785,293

 
176,399

 
89,978

 
1,156,355

 
282,705

STACK
 
11,932

 
535,356

 
101,158

 
16,855

 
672,968

 
129,016

Other
 
965

 
9,928

 
2,618

 

 

 

Total
 
347,825

 
1,964,289

 
675,206

 
409,271

 
2,627,325

 
847,159

The following table provides information regarding changes in total estimated proved reserves for the periods presented.  
 
 
Year Ended December 31,
MBoe
 
2018
 
2017
 
2016
Proved reserves at beginning of year
 
1,330,995

 
1,274,864

 
1,225,811

Revisions of previous estimates
 
(269,253
)
 
(82,012
)
 
(110,474
)
Extensions, discoveries and other additions
 
565,030

 
240,206

 
249,430

Production
 
(108,839
)
 
(88,562
)
 
(79,390
)
Sales of minerals in place
 
(8,011
)
 
(15,197
)
 
(10,513
)
Purchases of minerals in place
 
12,443

 
1,696

 

Proved reserves at end of year
 
1,522,365

 
1,330,995

 
1,274,864

Revisions of previous estimates. Revisions for 2018 are comprised of (i) the removal of 74 MMBo and 960 Bcf (totaling 234 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to the continual refinement of our drilling programs and reallocation of capital to areas providing the greatest opportunities to improve efficiencies, recoveries, and rates of return, (ii) downward revisions of 21 MMBo and 216 Bcf (totaling 57 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities and other factors, (iii) upward price revisions of 21 MMBo and 31 Bcf (totaling 26 MMBoe) due to an increase in average crude oil and natural gas prices in 2018 compared to 2017, and (iv) net downward revisions of 2 MMBo and 11 Bcf (totaling 4 MMBoe) due to changes in ownership interests, operating costs, anticipated production performance, and other factors.
Extensions, discoveries and other additions. Extensions, discoveries and other additions for each of the three years reflected in the table above were due to successful drilling and completion activities and continual refinement of our drilling programs in the Bakken, SCOOP, and STACK plays. Proved reserve additions in the Bakken totaled 251 MMBoe, 148 MMBoe, and 73 MMBoe for 2018, 2017, and 2016, respectively, while reserve additions in SCOOP totaled 186 MMBoe, 53 MMBoe, and 97 MMBoe for 2018, 2017, and 2016, respectively. Additionally, reserve additions in STACK totaled 128 MMBoe, 39 MMBoe, and 79 MMBoe in 2018, 2017, and 2016, respectively. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2018 drilling activities.
Sales of minerals in place. We had no individually significant dispositions of proved reserves in the past three years.
Purchases of minerals in place. We had no individually significant acquisitions of proved reserves in the past three years. The increase in acquired reserves in 2018 compared to prior years was due to higher mineral acquisition spending.

6



Proved Undeveloped Reserves
All of our PUD reserves at December 31, 2018 are located in the Bakken, SCOOP, and STACK plays, our most active development areas, with those plays comprising 52%, 33%, and 15%, respectively, of our total PUD reserves at year-end 2018. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2018. Our PUD reserves at December 31, 2018 include 89 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, 2017
 
322,242

 
2,441,120

 
729,094

Revisions of previous estimates
 
(95,168
)
 
(1,229,127
)
 
(300,022
)
Extensions and discoveries
 
222,122

 
1,612,969

 
490,950

Sales of minerals in place
 
(1,963
)
 
(24,327
)
 
(6,017
)
Purchases of minerals in place
 
2,457

 
33,563

 
8,051

Conversion to proved developed reserves
 
(40,419
)
 
(206,873
)
 
(74,897
)
Proved undeveloped reserves at December 31, 2018
 
409,271

 
2,627,325

 
847,159

Revisions of previous estimates. As previously discussed, in 2018 we removed 74 MMBo and 960 Bcf (totaling 234 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to the continual refinement of our drilling programs. Of these removals, 53 MMBo and 111 Bcf (totaling 72 MMBoe) was related to Bakken properties, 20 MMBo and 734 Bcf (totaling 142 MMBoe) was related to SCOOP properties, and 1 MMBo and 115 Bcf (totaling 20 MMBoe) was related to STACK properties. Additionally, aforementioned changes in anticipated well densities and other factors resulted in downward PUD reserve revisions of 21 MMBo and 216 Bcf (totaling 57 MMBoe) in 2018. Increases in average crude oil and natural gas prices in 2018 resulted in upward price revisions of 3 MMBo. Finally, changes in ownership interests, operating costs, anticipated production performance, and other factors resulted in net downward PUD reserve revisions of 3 MMBo and 53 Bcf (totaling 12 MMBoe) in 2018.
Extensions and discoveries. Extensions and discoveries were due to successful drilling activities and continual refinement of our drilling programs in the Bakken, SCOOP and STACK plays. PUD reserve additions in the Bakken totaled 159 MMBo and 410 Bcf (totaling 228 MMBoe) in 2018, while SCOOP PUD reserve additions totaled 53 MMBo and 662 Bcf (totaling 163 MMBoe) and STACK PUD reserve additions totaled 10 MMBo and 541 Bcf (totaling 100 MMBoe).
Purchases of minerals in place. Acquired PUD reserves in 2018 primarily reflect mineral acquisitions during the year, none of which were individually significant.
Conversion to proved developed reserves. In 2018, we developed approximately 19% of our PUD locations and 10% of our PUD reserves booked as of December 31, 2017 through the drilling and completion of 330 gross (122 net) development wells at an aggregate capital cost of $693 million incurred in 2018. PUD conversions in the Bakken totaled 33 MMBo and 82 Bcf (totaling 47 MMBoe) in 2018, while SCOOP PUD conversions totaled 6 MMBo and 36 Bcf (totaling 12 MMBoe) and STACK PUD conversions totaled 1 MMBo and 89 Bcf (totaling 16 MMBoe). These activities resulted in the conversion in 2018 of 15%, 4%, and 18%, respectively, of our Bakken, SCOOP, and STACK PUD reserves booked at year-end 2017.
In response to the significant improvement in crude oil prices in 2018, we refined our drilling programs to concentrate our efforts in areas and formations in Oklahoma and North Dakota offering the best opportunities to accelerate oil-weighted production growth. As part of this effort, we reallocated capital and rigs away from areas in the SCOOP and STACK plays having higher concentrations of natural gas to oil-weighted areas and formations. These factors resulted in the deferral or removal of previously planned PUD development projects primarily in the SCOOP play, which impacted our conversion of PUD reserves in 2018.
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. Our inventory of DUC wells classified as PUDs total 348 gross (141 net) operated and non-operated locations at December 31, 2018 and represent

7



10% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, 2018 and only the remaining completion costs are included in future development plans.
Estimated future development costs relating to the development of PUD reserves are projected to be approximately $2.5 billion in 2019, $2.2 billion in 2020, $1.7 billion in 2021, $1.4 billion in 2022, and $1.4 billion in 2023. These capital expenditure projections have been established based on an expectation of drilling and completion costs, available cash flows, borrowing capacity, and the commodity price environment in effect at the time of preparing our reserve estimates and may be adjusted as market conditions evolve. Development of our existing PUD reserves at December 31, 2018 is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be drilled within five years of initial booking because of changes in business strategy or for other reasons have been removed from our reserves at December 31, 2018. We had no PUD reserves at December 31, 2018 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, 98% of our PV-10 and 98% of our total proved reserves as of December 31, 2018 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 34 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 Reserves, Standardized Measure, and PV-10 Sensitivities
Our year-end 2018 proved reserves, Standardized Measure, and PV-10 estimates were prepared using 2018 average first-day-of-the-month prices of $65.56 per Bbl for crude oil and $3.10 per MMBtu for natural gas ($61.20 per Bbl for crude oil and $3.22 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, 2018 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 certain crude oil price scenarios, with natural gas prices being held constant at the 2018 average first-day-of-the-month price of $3.10 per MMBtu.

8



chart-a506cdca71be5327bdda01.jpg

9



The natural gas price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under certain natural gas price scenarios, with crude oil prices being held constant at the 2018 average first-day-of-the-month price of $65.56 per Bbl.
chart-d9edf235845e5fa6823a01.jpg

10



Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2018: 
 
 
Developed acres
 
Undeveloped acres
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
950,649

 
558,662

 
136,740

 
85,817

 
1,087,389

 
644,479

Montana Bakken
 
171,663

 
137,622

 
17,866

 
10,134

 
189,529

 
147,756

Red River units
 
158,077

 
139,796

 
20,462

 
9,821

 
178,539

 
149,617

Other
 
88,615

 
62,330

 
70,095

 
58,471

 
158,710

 
120,801

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
257,866

 
152,607

 
194,483

 
103,027

 
452,349

 
255,634

STACK
 
254,539

 
139,036

 
153,320

 
89,602

 
407,859

 
228,638

Other
 
61,744

 
28,971

 
70,748

 
33,380

 
132,492

 
62,351

East Region
 
943

 
848

 
158,613

 
135,490

 
159,556

 
136,338

Total
 
1,944,096

 
1,219,872

 
822,327

 
525,742

 
2,766,423

 
1,745,614


The following table sets forth the number of gross and net undeveloped acres as of December 31, 2018 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. 
 
 
2019
 
2020
 
2021
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
North Region:
 
 
 
 
 
 
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
 
 
 
 
 
 
North Dakota Bakken
 
3,050

 
1,669

 
29,684

 
20,401

 
32,530

 
23,205

Montana Bakken
 
400

 
400

 

 

 
1,480

 
1,480

Red River units
 
3,119

 
1,365

 

 

 

 

Other
 
20,417

 
13,963

 
3,755

 
1,343

 
17,217

 
17,217

South Region:
 
 
 
 
 
 
 
 
 
 
 
 
SCOOP
 
68,187

 
33,901

 
53,178

 
29,820

 
26,443

 
12,797

STACK
 
60,317

 
32,535

 
49,944

 
34,018

 
18,837

 
13,555

Other
 
28,115

 
12,005

 
24,094

 
12,094

 
1,164

 
721

East Region
 
55,347

 
40,336

 
11,728

 
10,164

 
969

 
370

Total
 
238,952

 
136,174

 
172,383

 
107,840

 
98,640

 
69,345



11



Drilling Activity
During the three years ended December 31, 2018, we drilled and completed exploratory and development wells as set forth in the table below:
 
 
2018
 
2017
 
2016
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
4

 
1.0

 
34

 
9.0

 
39

 
11.4

Natural gas
 
9

 
4.6

 
9

 
3.1

 
15

 
4.2

Dry holes
 

 

 

 

 

 

Total exploratory wells
 
13

 
5.6

 
43

 
12.1

 
54

 
15.6

Development wells:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil
 
636

 
213.7

 
474

 
175.4

 
245

 
54.7

Natural gas
 
151

 
39.1

 
91

 
26.8

 
66

 
21.6

Dry holes
 

 

 

 

 

 

Total development wells
 
787

 
252.8

 
565

 
202.2

 
311

 
76.3

Total wells
 
800

 
258.4

 
608

 
214.3

 
365

 
91.9

As of December 31, 2018, there were 490 gross (212 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 2019 in our key operating areas. Our 2019 capital budget has been set based on an expectation of available cash flows. Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, 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, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity prices decrease from current levels. Conversely, an increase in commodity prices from current levels could result in increased capital expenditures.
The following table provides information regarding well counts and budgeted capital expenditures for 2019.
 
 
2019 Plan
 
 
Gross wells (1)
 
Net wells (1)
 
Capital expenditures 
(in millions) (2)
 
 
Bakken
 
437

 
148

 
$
1,063

Oklahoma
 
228

 
109

 
1,102

Total exploration and development
 
665

 
257

 
$
2,165

Land (3)
 
 
 
 
 
205

Capital facilities, workovers and other corporate assets
 
 
 
 
 
228

Seismic
 
 
 
 
 
2

Total 2019 capital budget
 
 
 
 
 
$
2,600

(1) Represents operated and non-operated wells expected to have first production in 2019.
(2) Represents total capital expenditures for operated and non-operated wells expected to have first production in 2019 and wells spud that will be in the process of drilling, completing or waiting on completion as of year-end 2019.
(3)
Includes $125 million of planned spending for mineral acquisitions under our new relationship with Franco-Nevada Corporation described in Part II, Item 8. Notes to Consolidated Financial Statements—Note 15. Noncontrolling Interests. With a carry structure in place, Continental will recoup $100 million, or 80%, of such acquisition spending from Franco-Nevada.

12



North Region
Our properties in the North region represented 55% of our total proved reserves as of December 31, 2018 and 60% of our average daily Boe production for the fourth quarter of 2018. Our principal producing properties in the North region are located in the Bakken field.
Bakken Field
The Bakken field of North Dakota and Montana is one of the largest crude oil resource plays in the United States. We are a leading producer, leasehold owner and operator in the Bakken. As of December 31, 2018, we controlled one of the largest leasehold positions in the Bakken with approximately 1.3 million gross (792,200 net) acres under lease.
Our total Bakken production averaged 183,836 Boe per day for the fourth quarter of 2018, up 11% from the 2017 fourth quarter. For the year ended December 31, 2018, our average daily Bakken production increased 26% over 2017. We increased our drilling and well completion activities in the Bakken in 2018 in response to improved crude oil prices. In 2018, we participated in the drilling and completion of 496 gross (169 net) wells in the Bakken compared to 370 gross (145 net) wells in 2017. Our 2018 activities in the Bakken focused on ongoing development of high rate-of-return areas in core parts of the play.
Our Bakken properties represented 52% of our total proved reserves at December 31, 2018 and 57% of our average daily Boe production for the 2018 fourth quarter. Our total proved Bakken field reserves as of December 31, 2018 were 798 MMBoe, an increase of 26% compared to December 31, 2017 primarily due to reserves added from our drilling program and continued improvement in recoveries driven by advances in optimized completion designs. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,629 gross (930 net) wells as of December 31, 2018.
In 2019, we plan to invest approximately $1.06 billion in the Bakken play to drill, complete and initiate production on 437 gross (148 net) operated and non-operated wells. We plan to average approximately six operated rigs and four well completion crews in the Bakken throughout 2019. Our 2019 drilling and completion activities will focus on core parts of the Bakken that provide opportunities to improve capital efficiency, reduce finding and development costs, grow our oil-weighted production, and improve recoveries and rates of return.
South Region
Our properties in the South region represented 45% of our total proved reserves as of December 31, 2018 and 40% of our average daily Boe production for the fourth quarter of 2018. Our principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.
SCOOP
The SCOOP play 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, 2018, we controlled one of the largest leasehold positions in SCOOP with approximately 452,300 gross (255,600 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. Our Springer and Sycamore positions supplement our Woodford leasehold and expand our resource potential and inventory in the play. 
SCOOP represented 30% of our total proved reserves as of December 31, 2018 and 21% of our average daily Boe production for the fourth quarter of 2018. Production in SCOOP averaged 67,244 Boe per day during the fourth quarter of 2018, up 8% compared to the 2017 fourth quarter. For the year ended December 31, 2018, average daily production in SCOOP increased 6% compared to 2017, reflecting increased drilling and completion activities in 2018. We participated in the drilling and completion of 148 gross (48 net) wells in SCOOP during 2018 compared to 77 gross (20 net) wells in 2017. Proved reserves in SCOOP totaled 459 MMBoe as of December 31, 2018, a decrease of 7% compared to December 31, 2017 primarily due to the aforementioned removal of PUD reserves no longer scheduled to be drilled within five years of initial booking partially offset by new reserve extensions and discoveries. Our inventory of proved undeveloped drilling locations in SCOOP totaled 471 gross (248 net) wells as of December 31, 2018.
Our 2018 activities in SCOOP were focused on a new development project in the play named Project SpringBoard. SpringBoard is a massive, multi-year, crude oil project controlled and operated by Continental that covers approximately 73 square miles of contiguous leasehold in Grady County, Oklahoma where we are concurrently developing three stacked reservoirs in the Springer, Sycamore, and Woodford formations. These reservoirs are being developed in rows to maximize

13



efficiencies and rates of return through the orderly sequencing of drilling and completion activities. This row development strategy allows us to realize significant cost savings. In addition to cost saving benefits, our SpringBoard production benefits from access to premium sales markets through existing pipeline infrastructure, making our SpringBoard sales price realizations among the best in the Company. Additionally, water pipeline and recycling facilities are in place to allow for uninterrupted flow back and recycling capabilities to support timely completion activities in the project. Project SpringBoard marks the beginning of full scale development of our SCOOP oil assets, following years of leasing, exploration, and delineation drilling, and is expected to have a meaningful impact on the Company's oil-weighted production growth in 2019.
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, 2018, we controlled one of the largest leasehold positions in STACK with approximately 407,900 gross (228,600 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.
Our STACK properties represented 15% of our total proved reserves as of December 31, 2018 and 19% of our average daily Boe production for the fourth quarter of 2018. Production in STACK increased to an average rate of 62,947 Boe per day during the fourth quarter of 2018, up 31% over the 2017 fourth quarter due to additional wells being completed and producing. For the year ended December 31, 2018, average daily production in STACK grew 55% over 2017. We participated in the drilling and completion of 154 gross (40 net) wells in STACK during 2018 compared to 160 gross (49 net) wells in 2017. Our 2018 activities were focused on accelerating the development of our oil and liquids-rich assets in the play. Highlighting our 2018 activity in the play was the completion of three units (Jalou, Homsey, Simba) targeting the Meramec formation in the over-pressured oil and condensate windows of STACK. These three units produced outstanding results that confirmed our unit development model and the economic producibility of the reservoirs in the play.
Proved reserves in STACK increased 38% year-over-year to 230 MMBoe as of December 31, 2018 due to reserves added from our drilling program and continued improvement in recoveries driven by advances in optimized completion designs. Our inventory of proved undeveloped drilling locations in STACK totaled 262 gross (84 net) wells as of December 31, 2018.
In Oklahoma, for 2019 we plan to invest an aggregate of approximately $1.10 billion to drill, complete and initiate production on 228 gross (109 net) operated and non-operated wells in the SCOOP and STACK areas combined. We plan to average approximately 19 operated rigs, with 12 rigs focused on Project SpringBoard, and five well completion crews in Oklahoma throughout 2019. Our 2019 activities in SCOOP will focus on continued row development in Project SpringBoard and achieving operational and technical advancements aimed at further improving capital efficiencies, oil-weighted production growth, and rates of return. Our 2019 activities in STACK will focus on continued development of oil and liquids-rich assets in the over-pressured windows of the play and improving capital efficiencies, recoveries, and rates of return.

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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, 2018, 2017 and 2016 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2018.  
 
 
Year ended December 31,
 
 
2018
 
2017
 
2016
Net production volumes:
 
 
 
 
 
 
Crude oil (MBbls)
 
 
 
 
 
 
North Dakota Bakken
 
45,775

 
35,964

 
31,723

SCOOP
 
6,918

 
5,726

 
6,807

STACK
 
3,582

 
3,166

 
1,552

Total Company
 
61,384

 
50,536

 
46,850

Natural gas (MMcf)
 
 
 
 
 
 
North Dakota Bakken
 
78,448

 
59,232

 
50,532

SCOOP
 
99,397

 
98,563

 
102,032

STACK
 
101,267

 
60,325

 
27,983

Total Company
 
284,730

 
228,159

 
195,240

Crude oil equivalents (MBoe)
 
 
 
 
 
 
North Dakota Bakken
 
58,849

 
45,836

 
40,145

SCOOP
 
23,484

 
22,153

 
23,813

STACK
 
20,460

 
13,220

 
6,216

Total Company
 
108,839

 
88,562

 
79,390

Average net sales prices (1):
 
 
 
 
 
 
Crude oil ($/Bbl)
 
 
 
 
 
 
North Dakota Bakken
 
$
58.37

 
$
45.21

 
$
34.33

SCOOP
 
62.74

 
47.96

 
38.87

STACK
 
61.97

 
49.68

 
41.95

Total Company
 
59.19

 
45.70

 
35.51

Natural gas ($/Mcf)
 
 
 
 
 
 
North Dakota Bakken
 
$
3.33

 
$
2.97

 
$
1.05

SCOOP
 
3.41

 
3.26

 
2.24

STACK
 
2.38

 
2.43

 
1.87

Total Company
 
3.01

 
2.93

 
1.87

Crude oil equivalents ($/Boe)
 
 
 
 
 
 
North Dakota Bakken
 
$
49.83

 
$
39.32

 
$
28.45

SCOOP
 
32.88

 
26.93

 
20.71

STACK
 
22.68

 
22.89

 
18.88

Total Company
 
41.25

 
33.65

 
25.55

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

 
$
4.40

 
$
4.59

SCOOP
 
1.34

 
1.01

 
1.13

STACK
 
1.21

 
1.22

 
1.00

Total Company
 
3.59

 
3.66

 
3.65

Production taxes ($/Boe)
 
$
3.25

 
$
2.35

 
$
1.79

General and administrative expenses ($/Boe)
 
$
1.69

 
$
2.16

 
$
2.14

DD&A expense ($/Boe)
 
$
17.09

 
$
18.89

 
$
21.54


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(1)
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures for 2018.
The following table sets forth information regarding our average daily production by region for the fourth quarter of 2018: 
 
 
Fourth Quarter 2018 Daily Production
 
 
Crude Oil
(Bbls per day)
 
Natural Gas
(Mcf per day)
 
Total
(Boe per day)
North Region:
 
 
 
 
 
 
Bakken field
 
 
 
 
 
 
North Dakota Bakken
 
139,338

 
228,124

 
177,358

Montana Bakken
 
4,998

 
8,881

 
6,478

Red River units
 
 
 
 
 
 
Cedar Hills
 
6,389

 
1,255

 
6,598

Other Red River units
 
2,048

 
2,385

 
2,446

Other
 
33

 

 
33

South Region:
 
 
 
 
 
 
SCOOP
 
21,332

 
275,471

 
67,244

STACK
 
12,402

 
303,272

 
62,947

Other
 
394

 
3,014

 
897

Total
 
186,934

 
822,402

 
324,001

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, 2018. 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
 
4,506

 
1,446

 

 

 
4,506

 
1,446

Montana Bakken
 
401

 
263

 

 

 
401

 
263

Red River units
 
 
 
 
 
 
 
 
 
 
 


Cedar Hills
 
135

 
129

 

 

 
135

 
129

Other Red River units
 
128

 
114

 

 

 
128

 
114

Other
 
2

 
2

 

 

 
2

 
2

South Region:
 
 
 
 
 
 
 
 
 
 
 

SCOOP
 
335

 
184

 
438

 
126

 
773

 
310

STACK
 
257

 
82

 
353

 
123

 
610

 
205

Other
 
101

 
80

 
126

 
40

 
227

 
120

Total
 
5,865

 
2,300

 
917

 
289

 
6,782

 
2,589


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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 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. Company landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.
Prior to the commencement of drilling operations, Company landmen 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. Company landmen will not approve commencement of drilling operations until material title defects pertaining to the Company’s interest are cured.
The Company has cured material title opinion defects as to Company interests on substantially all of its producing properties and believes it holds at least defensible title to its producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. The Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the Company’s interest in the properties or affect the Company’s carrying value of such properties.
Marketing and Major Customers
We sell most of our operated crude oil production to crude oil refining companies or midstream marketing companies at major market centers. 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 either directly to a refinery or to a point on a pipeline system for further delivery. We do not transport any of our oil production prior to sale by rail, but several purchasers of our Bakken production are connected to rail delivery systems and may choose those methods to transport the oil they purchase from us. We sell some operated crude oil production at the lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.
We sell our operated natural gas production to midstream customers at our lease locations based on market prices in the field where the sales occur. These contracts include multi-year term agreements, many with acreage dedication. Under certain arrangements, we have the right to take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of our operated natural gas production. We currently take certain processed residue gas volumes in kind in lieu of monetary settlement, but we do not take NGL volumes. When we do take volumes in kind, we pay third parties to transport the residue gas volumes taken in kind to downstream delivery points, where we then sell to customers at prices applicable to those downstream markets. Sales at the 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 products we elect to take in-kind in lieu of monetary settlement for our leasehold sales. Our share of natural gas production from non-operated properties is generally marketed at the discretion of the operators.
For the year ended December 31, 2018, sales to Valero Energy Corporation and its affiliates accounted for approximately 12% 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 2018. 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

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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 sustained commodity price recovery.
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 frequent 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 our operations and may increase the cost of doing business and reduce our 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 future legislative or regulatory initiatives will affect us 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
Our physical sales of crude oil and any derivative instruments relating to crude oil are subject to anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”) that, among other things, prohibit fraudulent or deceptive conduct in connection with wholesale purchases or sales of crude oil and price manipulation in the commodity and futures markets. 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.
We transport most of our operated crude oil production to market centers using a combination of trucks and pipeline transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration establishes safety regulations relating to transportation of crude oil by pipeline. Further, our sales of crude oil are affected by the availability, terms and costs of transportation. The transportation of crude oil and natural gas liquids ("NGLs") 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. In general, pipeline rates must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. 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 such 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.
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 legislation eliminating the ban on crude oil exports beginning in January 2016. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. The International Maritime Organization ("IMO"), an agency of the United Nations, has issued regulations requiring the maritime shipping industry to gradually reduce its carbon emissions over time by mandating a 1% improvement in the efficiency of fleets each year between 2015 and 2025. In conjunction with this initiative, the IMO has issued regulations requiring ship owners to lower the concentration of the sulfur content used in their fuels from 3.5% to 0.5% beginning in 2020. To achieve this goal, ship owners will either have to switch to more expensive higher quality marine fuel, invest in emissions-cleaning systems, or switch to alternative fuels such as liquefied natural gas. Third party compliance with the IMO's shipping regulations may result in exportation capacity constraints during the period in which tanker fleets are retrofitted to meet specifications, thereby inhibiting a third party's ability to transport and sell our crude oil production overseas, which may have a material impact on the markets and prices for various grades of domestic and international crude oil.

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We do not own or operate pipeline or rail transportation facilities, rail cars, or infrastructure used to facilitate the exportation of crude oil. However, regulations that impact the domestic 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. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.
Regulation of sales and transportation of natural gas
We are also required to observe the aforementioned anti-market manipulation laws and related regulations enforced by the FERC and CFTC in connection with physical sales of natural gas and derivative instruments relating to natural gas. Additionally, the FERC regulates interstate natural gas transportation rates and service conditions under the Natural Gas Act and the Natural Gas Policy Act of 1978, 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 increase competition and make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis and has issued a series of orders to implement its open access policies. 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 the FERC will affect us in a materially different way than similarly situated natural gas producers.
The gathering of natural gas, 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 costs for our purchasers and reduce the revenues we receive for our natural gas stream. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, equitable take requirements. We do not believe such regulations will affect us 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 will not affect us in a way that materially differs from our similarly situated competitors.
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 and could inhibit the development of LNG infrastructure.
Regulation of production
The production of crude oil and natural gas is regulated by a wide range of federal, state and local laws, 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 laws and 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, the regulation of greenhouse gas emissions, and limitations or prohibitions on the venting or flaring of natural gas. These laws and regulations directly and indirectly 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 laws and 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 the above laws, rules, and regulations can result in substantial penalties. Our similarly situated competitors are generally subject to the same laws, rules, and regulations as we are.
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:

19



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 legislators and 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 and production of oil and gas.
Failure to comply with these and other 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. The following is a description of some of the environmental laws, rules and regulations that apply to our operations.
Air emissions and climate change. Federal, state and local laws and regulations have been and may be enacted to address concerns about the potential effects of carbon dioxide, methane and other identified “greenhouse gas” emissions on the environment and climate worldwide, generally referred to as “climate change.” For example, in October 2015 the U.S. Environmental Protection Agency ("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. 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.
With respect to climate change and the control of greenhouse gas emissions, recent federal regulatory initiatives have focused on reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. For example, in June 2016 the EPA finalized new regulations (New Source Performance Standard 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. The U.S. Department of Interior’s Bureau of Land Management (“BLM”) finalized similar regulations in November 2016 for new and existing oil and gas operations on federal lands. Following the change in U.S. presidential administrations in 2016, there have been attempts to modify these regulations, and litigation concerning the regulations is ongoing. As a result, we cannot predict the scope of any final methane-related regulatory requirements or the cost to comply with such requirements. Some states have also imposed similar regulations on oil and gas operations, and it is possible new methane emission standards could be proposed in the future. However, we do not expect such measures will 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. Following the change in U.S. presidential administrations, 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.
While we cannot predict the outcome of legislative or regulatory initiatives related to climate change, we anticipate that initiatives to reduce greenhouse gas emissions will continue to develop. The adoption of state or federal legislation or regulatory programs to reduce greenhouse gas emissions, including methane and carbon dioxide, could require us to incur increased operating costs, such as costs to purchase and operate emissions monitoring and control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming hydrocarbons and thereby reduce demand for the crude oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce greenhouse gas emissions could have an adverse effect on our business, financial condition, results of operations, and cash flows.

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Environmental protection and natural gas flaring. 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 North Dakota Industrial Commission ("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. In addition, 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. The NDIC currently requires us to capture 88% of the natural gas produced from a field, and beginning November 1, 2020 the target capture rate increases to 91%. 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.
We continue to strive to reduce natural gas flaring as much as practicable, but our efforts may not always be successful or cost-effective. Increased emissions from our facilities due to flaring could subject our facilities to more stringent air emission permitting requirements, resulting in increased compliance costs and potential construction delays.
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 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 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 regulation on us is not currently, and 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 which the EPA indicated it found evidence that such activities can impact drinking water resources under some circumstances. 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. However, the BLM subsequently rescinded the rules in December 2017. Litigation challenging the BLM's rescission has been filed by certain states and environmental groups and remains ongoing. As of December 31, 2018, we held approximately 59,700 net undeveloped acres on federal land, representing approximately 11% of our total net undeveloped acres.
In addition, regulators in states in which we operate have adopted or 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 natural 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 curtailment or even 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. 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.
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

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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 utilizes 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 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.
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 business, financial condition, results of operations or cash flows.

Employee Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state laws 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 laws and regulations require information be maintained about hazardous materials used or produced in operations and this information be provided to employees, state and local governmental authorities and citizens.
Employees
As of December 31, 2018, we employed 1,221 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, investors should monitor that portion of our website in addition to following our press releases, SEC filings and public conference calls and webcasts.
We electronically file periodic reports and proxy statements with the SEC. The SEC maintains an internet website that contains reports, proxy and information statements, and other information registrants file 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, cash flows, access to capital, capital budget, rate of growth, and carrying value of our properties. 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 2018 the NYMEX West Texas Intermediate (“WTI”) crude oil and Henry Hub natural gas spot prices ranged from approximately $44 to $77 per barrel and $2.49 to $6.24 per MMBtu, respectively. Commodity prices will likely remain volatile and unpredictable in 2019 and beyond.
We have hedged the majority of our forecasted 2019 natural gas production. Our future crude oil production is currently unhedged and is 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, natural gas, and natural gas liquids;
the actions of the Organization of Petroleum Exporting Countries and other producing nations;
the nature and extent of domestic and foreign governmental laws, regulations, and taxation, including environmental laws and regulations governing the imposition of trade restrictions and tariffs;
the level of global, national, and regional crude oil and natural gas exploration and production activities;
the level of global, national, and regional crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;
the level and effect of speculative 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 nations;
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, natural gas, and natural gas liquids;
adverse weather conditions and natural disasters;
technological advances affecting energy production and 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 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.

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Lower commodity prices may also lead to reductions in our drilling and completion programs, which may result in insufficient production to satisfy our transportation and processing commitments. If production is not sufficient to meet our commitments we would incur deficiency fees that would need to be paid absent any cash inflows generated from the sale of production.
Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating. 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.
Volatility in the financial markets or in global economic factors, including consequences resulting from international trade disputes and tariffs, could adversely impact our business.
United States and global economies may experience periods of volatility and uncertainty from time to time, resulting in unstable consumer confidence, diminished consumer demand and spending, diminished liquidity and credit availability, and inability to access capital markets. 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 have a negative impact on commodity prices and the availability and cost of materials used in our industry, which in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The current administration in the United States has expressed concerns in recent years about imports from countries it perceives are engaging in unfair trade practices. In 2018, the United States government initiated tariffs on certain imported goods and has raised the possibility of imposing tariff increases on such goods or expanding the scope of tariffs to include other types of imported goods. In response, certain foreign governments, most notably China, have imposed retaliatory tariffs on certain goods their countries import from the United States. These and other events, including the United Kingdom's potential withdraw from the European Union, have contributed to increased economic uncertainty and diminished expectations for the global economy.
Trade restrictions or other governmental actions related to tariffs or trade policies have impacted, and have the potential to further impact, our business and industry. For instance, in 2018 the United States government imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and aluminum products from various countries. The oil and gas industry in the United States utilizes significant amounts of steel in the drilling and completion of new wells and for construction of facilities, pipelines, processing plants, and refineries. The steel required to meet the needs of our industry may not be domestically available in sufficient quantities, particularly in periods of favorable commodity prices. Thus, current and future tariffs may increase the cost of materials used in various aspects of upstream, midstream, and downstream oil and gas activities which, in turn, could increase our cost of doing business. Furthermore, the tariffs and quantitative import restrictions may cause disruption in the energy industry’s supply chain, resulting in the delay or cessation of drilling and completion efforts or the postponement or cancellation of new pipeline transportation projects the U.S. industry is relying on to transport its increasing levels of onshore production to market, as well as endangering U.S. liquefied natural gas export projects resulting in negative impacts on natural gas production. Additionally, trade and/or tariff disputes could have negative impacts on the domestic and global economies overall, which could result in reduced demand for crude oil and natural gas. Any of the above consequences could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our producing properties are 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 56% of our crude oil and natural gas production and approximately 68% of our crude oil and natural gas revenues for the year ended December 31, 2018. Approximately 52% of our estimated proved reserves were located in the Bakken as of December 31, 2018. 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 27% of our crude oil and natural gas revenues for the year ended December 31, 2018. Approximately 45% of our estimated proved reserves were located in Oklahoma as of December 31, 2018.
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

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regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; (ii) the availability of rigs, completion crews, equipment, field services, supplies, and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the Bakken field and Oklahoma may be adversely affected by severe weather events such as floods, blizzards, ice storms and tornadoes, which can intensify competition for the items 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, cyber attacks, 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 business, financial condition, results of operations and cash flows.
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 $2.6 billion for capital expenditures in 2019 of which approximately $2.2 billion is allocated to exploration and development activities. We may adjust our 2019 capital spending plans upward or downward depending on market conditions. Our 2019 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows and, if necessary, through borrowings under our credit facility. However, the sufficiency of our cash flows from operations and access to capital are subject to a number of variables, including but not limited to:
the prices at which crude oil and natural gas are sold;
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;
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, we may not be able to generate sufficient cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. A decline in cash flows from operations may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities.
We have a revolving credit facility with lender commitments totaling $1.5 billion that matures in April 2023. 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.
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, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.

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Risks we face while drilling include, but are not limited to, failing to place our well bore in the desired target producing zone; not staying in the desired drilling zone while drilling horizontally through the formation; failing to run our casing the entire length of the well bore; and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages; failing to run tools the entire length of the well bore during completion operations; not successfully cleaning out the well bore after completion of the final fracture stimulation stage; increased seismicity in areas near our completion activities; 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:
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 may turn out to be inaccurate. Any material inaccuracies in our 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 due to changes in commodity prices, business strategies, and other factors.
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, 2018.
In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. Proved undeveloped reserves generally must be drilled 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 2018, 234 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with locations no longer scheduled to be drilled within five years from the date of initial booking.

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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 projected into the future, about 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, 2018, average prices used to calculate our estimated proved reserves were $65.56 per Bbl for crude oil and $3.10 per MMBtu for natural gas ($61.20 per Bbl for crude oil and $3.22 per Mcf for natural gas adjusted for location and quality differentials). Actual future prices may be materially higher or lower than those used in our year-end estimates. NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity prices for January 1, 2019 and February 1, 2019 averaged $50.34 per barrel and $3.03 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 sales 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 remove or adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development activities, changes in business strategies, prevailing crude oil and natural gas prices and other factors, some 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. 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. 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 field 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, personnel, field services, and supplies, 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 field service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages and/or higher costs. Such shortages or higher costs could delay the execution of our drilling and development plans 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 associated with our business. Losses and liabilities arising from uninsured and under-insured events could materially and adversely affect our business, financial condition or results of operations. Our 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;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations;
repair and remediation costs; and
litigation.

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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 produce crude oil or natural gas in expected quantities.
Prospects we decide to drill that do not produce crude oil or natural gas in expected quantities may adversely affect our results of operations, financial condition, and rates of return on capital employed. In this report, we describe some of our current prospects and plans to develop our key operating areas. It is not possible to predict with certainty whether any particular prospect will produce crude oil or natural gas in sufficient quantities to recover drilling and completion costs, achieve desired recoveries and rates of return, 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 in expected or economically producible quantities. We cannot assure you the wells we drill will be as productive as anticipated or whether the analogies we draw 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 our potential drilling locations 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 60% of our total net undeveloped acreage at December 31, 2018. At that date, we had leases representing 136,174 net acres expiring in 2019, 107,840 net acres expiring in 2020, and 69,345 net acres expiring in 2021. 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, 2018, approximately 56% 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, 2018 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $9.2 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 generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any proved undeveloped reserves not developed within this five-year time frame. Such removals have occurred in the past and may occur in the future. A removal of such reserves could adversely affect our operations. In 2018, 234 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with locations no longer scheduled to be drilled within five years from the date of initial booking.



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Our business depends on crude oil and natural gas transportation, processing, refining, and export 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, refining, and export 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, refining, or export facilities due to labor disputes, maintenance, civil disturbances, international trade disputes, 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 or processing commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings in the absence of sufficient operating cash flows.
Our operated crude oil and natural gas production is ultimately transported to downstream market centers in the United States primarily using transportation facilities and equipment 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. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. We do not currently own or operate infrastructure used to facilitate the transportation and exportation of crude oil; however, third party compliance with regulations that impact the transportation or exportation of our production may increase our costs of doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally, the consequences of which could have a material adverse effect on our business, 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 or completion 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 in recent years 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, have imposed or are considering additional requirements related to seismicity. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Waste water disposal for further discussion of regulations that affect us.
Compliance with existing or new environmental laws, 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.

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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, occupational health and safety, 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 investigations or actions, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations, criminal sanctions, or 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, 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 laws or regulations, 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 laws and regulations 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, restrictions on transportation of production, new safety requirements, 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.
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. 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. 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. 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 status of such regulations. Undoing previously existing regulations has and likely will continue to involve lengthy notice-and-comment rulemaking, and the resulting decisions have been and likely will continue to be subject to litigation by opposition groups. Thus, the scope and impact of existing and potential future regulations remains substantially uncertain with respect to the implementation of climate-related public policies. However, given the long-term trend towards increasing regulation, future federal greenhouse gas regulations of the oil and gas industry remain possible, and certain states have separately imposed their own regulations on emissions from oil and gas production activities and other states may do so as well.
The implementation of, and compliance with, laws and 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

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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. Moreover, activists concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has and may yet result in financial institutions, funds, and other sources of capital restricting or eliminating their investment in crude oil and natural gas activities. 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 laws and regulations 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 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 proposed and enacted laws and regulations have emerged which could 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 laws and regulations 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.

Future legislation may impose new taxes on crude oil or natural gas activities, including eliminating or reducing certain federal income tax deductions currently available with respect to crude oil and natural gas exploration and development.
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 were not impacted by the Tax Cuts and Jobs Act signed into law in the United States in December 2017. 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. Any such changes could adversely affect our business, financial condition, results of operations and cash flows.
We are involved in legal proceedings that could result in substantial liabilities.
Like other similarly-situated oil and gas companies, we are, from time to time, involved in various legal proceedings in the ordinary course of business including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities, and other matters. The outcome of such legal matters often cannot be predicted with certainty. We vigorously defend ourselves in all such matters. However, if our efforts to defend ourselves are not successful, it is possible the outcome of one or more such proceedings could result in substantial liability, penalties, sanctions, judgments, consent decrees, or orders requiring a change in our business

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practices, which could have a material adverse on our business, financial condition, results of operations and cash flows. Judgments and estimates to determine accruals related to legal and other proceedings could change from period to period, and such changes could be material.
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 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. 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, our competitors 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 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 enforcement interpretations or a reduction in demand for our products. 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 or third party service providers need to conduct 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, floods, 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 regions. The consequences of such events may include the evacuation of personnel; damage to and disruption of drilling rigs or transportation, processing, storage, refining, and export 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.

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Regulations under the Dodd-Frank Act regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risk and other risks associated with our business.
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, established federal oversight and regulation of the over-the-counter derivatives market and required the Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to derivative transactions. If we do not qualify for an end user exemption from the Dodd-Frank Act requirements, the new regulations could increase the cost 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, and increase our exposure to less creditworthy counterparties, any of which could limit our desire and ability to implement commodity price risk management strategies. 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. While certain Dodd-Frank Act regulations are already in effect, certain aspects of the rulemaking have been repealed or have not been finalized and the ultimate effect of the regulations on our business remains uncertain.
The loss of senior management or technical personnel could adversely affect our operations.
We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2018, non-operated properties represented 19% of our estimated proved developed reserves, 12% of our estimated proved undeveloped reserves, and 15% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including the marketing of oil and gas production, 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 operators 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 business, 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, 2018, we had no outstanding borrowings on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.43 to 1.00. Our total debt would need to independently increase by approximately $8.1 billion above the existing level at December 31, 2018 (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 $4.3 billion below the existing level at December 31, 2018 (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 the 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 covenant 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

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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 have a material adverse effect our business, financial condition, results of operations, and cash flows.
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 rely heavily on digital technologies, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. The availability and integrity of these systems are essential for us to conduct our operations. Our business associates, including employees, vendors, service providers, financial institutions, and transporters, processors, and purchasers of our production are also heavily 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 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 of our systems and those of our business associates, may remain undetected for an extended period.
A cyber attack involving our information systems and related infrastructure, and/or that of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to:
unauthorized access to or theft of seismic data, reserves information, strategic information, or other sensitive or proprietary information owned by us or by third parties could have a negative impact on our ability to compete for oil and gas resources;
data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;
data corruption or operational disruption of production-related infrastructure could result in a loss of production or accidental discharge;
a cyber attack on third party transportation, processing, storage, refining, or export facilities could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;
a cyber attack involving commodity exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
corruption of our financial or operating data could result in events of non-compliance which could lead to regulatory fines or penalties; and
a cyber attack could result in unauthorized access to and release of personal or confidential information maintained by the Company.
Any of the above 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 business, financial condition, results of operations or cash flows.
The Company has established cyber security systems and controls intended to monitor threats, identify incidents and assess their impact, protect information, and mitigate data loss. The Company has also established disclosure controls and procedures in tandem with incident response protocols, including regular assessment of threats and incidents by a security oversight committee comprised of members of senior management and information technology personnel. These systems, controls, and procedures are intended to provide information about cyber security incidents so that such information can be timely processed and reported to the appropriate personnel; however, these systems, controls, and procedures may not identify all risks and threats we face, or may fail to protect data or mitigate the adverse effects of data loss. Our senior management makes materiality assessments and disclosure decisions and has implemented procedures to prohibit insider trading on the basis of material nonpublic information about cyber incidents; however, we cannot guarantee all of these efforts will be effective. Although we maintain systems, controls, and procedures to address cyber security risks, such measures cannot eliminate cyber

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security threats and incidents, and there remains a risk that we will experience a cyber breach, attack, or data loss incident and suffer adverse effects.
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 either as a result of a breach of our systems or those of our business associates. 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. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which may impose significant costs that are likely to increase over time.
Increases in interest rates could adversely affect our business.
The U.S. Federal Reserve increased the benchmark federal funds interest rate on four separate occasions in 2018 and is forecasting additional increases in 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, disposition, or joint development opportunities, reduce cash flows used for drilling and completion activities, and place us at a competitive disadvantage. 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.
Financial regulators are working to transition away from the London Interbank Offered Rate (“LIBOR”) as a reference rate for financial contracts by the end of 2021 and to develop benchmarks to replace LIBOR. Certain types of borrowings under our revolving credit facility, which matures in April 2023, are derived from the LIBOR reference rate. Our revolving credit agreement includes general provisions governing the establishment of an alternate rate of interest to the LIBOR-based rate that gives consideration to the then prevailing market convention for determining a rate of interest for comparable syndicated loans. At this time, the impact on the Company's borrowing costs, if any, under an alternative reference rate scenario is uncertain.
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 ($644 million in receivables at December 31, 2018); our joint interest and other receivables ($368 million at December 31, 2018); and counterparty credit risk associated with our derivative instrument receivables ($16 million at December 31, 2018). These counterparties may experience insolvency or liquidity issues and may not be able to meet their obligations and liabilities owed to us, particularly during a period of depressed commodity prices. Defaults by these counterparties could adversely impact our financial condition and results of operations.
Additionally, we rely on field 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 business, 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 potentially significant 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, 2018. 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 materially as a result of changes in commodity prices and resulting changes in the fair value of our derivatives.
Derivative instruments expose us to the risk of financial loss in certain circumstances, including when:
production is less than the volume covered by the derivative instruments;
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.

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In addition, our derivative arrangements limit the benefit we would otherwise 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 2019 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, 2018, 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 or persons 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 parties 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 in the emerging areas 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 assets, and enter into joint development arrangements. Suitable acquisition properties, buyers of our 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 property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

37



In addition, from time to time we may sell or otherwise dispose of certain 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. The occurrence of any of the matters described above could have an adverse impact on our business, financial condition, results of operations and cash flows.
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 abroad 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. Any of these events could materially and adversely affect our business and results of operations.

Item 1B.    Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2018.
 
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 11. Commitments and Contingencies–Litigation in Part II, Item 8. Financial Statements and Supplementary Data–Notes to Consolidated Financial Statements for a discussion of the legal matter involving the Company, Billy J. Strack and Daniela A. Renner, which is incorporated herein by reference.

Item 4.
Mine Safety Disclosures
Not applicable.

38



Part II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange and trades under the symbol “CLR.” As of January 31, 2019, the number of record holders of our common stock was 1,234. Management believes, after inquiry, that the number of beneficial owners of our common stock is approximately 71,370. On January 31, 2019, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $46.17 per share.
The following table summarizes our purchases of our common stock during the quarter ended December 31, 2018:
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, 2018 to October 31, 2018
 
785

 
$
52.68

 

 

November 1, 2018 to November 30, 2018
 
11,389


$
48.00

 

 

December 1, 2018 to December 31, 2018
 



 

 

Total
 
12,174

 
$
48.30

 

 

 
(1)
In connection with restricted stock grants under the Company’s 2013 Long-Term Incentive Plan (“2013 Plan”), we adopted a policy that enables employees to surrender shares to cover their tax liability. Shares indicated as having been purchased in the table above represent shares surrendered by employees to cover tax liabilities. We paid the associated taxes to the applicable taxing authorities.
(2)
The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.
Equity Compensation Plan Information
The following table sets forth the information as of December 31, 2018 relating to equity compensation plans:
 
 
 
Number of Shares
to be Issued Upon
Exercise of
Outstanding
Options
 
Weighted-Average
Exercise Price of
Outstanding Options
 
Remaining Shares
Available for Future
Issuance Under Equity
Compensation Plans (1)
Equity Compensation Plans Approved by Shareholders
 

 

 
13,736,734

Equity Compensation Plans Not Approved by Shareholders
 

 

 

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

39



Performance Graph
The following graph compares our common stock performance with the performance of the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Dow Jones US Oil and Gas Index (“Dow Jones US O&G Index”) for the period of December 31, 2013 through December 31, 2018. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, 2013 and that any dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.
The information provided in this section is being furnished to, and not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.
chart-55506f2e743f54a68ffa01.jpg


40



Item 6.
Selected Financial Data
This section presents selected consolidated financial data for the years ended December 31, 2014 through 2018. The selected financial data presented below is not intended to replace our consolidated financial statements.
The following financial data has been derived from our audited consolidated financial statements for such periods. You should read the following selected financial data in connection with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and related notes included elsewhere in this report. The selected consolidated results are not necessarily indicative of results to be expected in future periods. Operating and financial results attributable to noncontrolling interests are immaterial and are not separately presented below.
 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
 
2015
 
2014
Income Statement data
 
 
 
 
 
 
 
 
 
 
In thousands, except per share data
 
 
Crude oil and natural gas sales (1)
 
$
4,678,722

 
$
2,982,966

 
$
2,026,958

 
$
2,552,531

 
$
4,203,022

Gain (loss) on crude oil and natural gas derivatives, net (2)
 
(23,930
)
 
91,647

 
(71,859
)
 
91,085

 
559,759

Total revenues
 
4,709,586

 
3,120,828

 
1,980,273

 
2,680,167

 
4,801,618

Net income (loss) (3)
 
989,700

 
789,447

 
(399,679
)
 
(353,668
)
 
977,341

Net income (loss) attributable to Continental Resources (3)(4)
 
988,317

 
789,447

 
(399,679
)
 
(353,668
)
 
977,341

Net income (loss) per share attributable to Continental Resources: (3)(4)
 
 
 
 
 
 
 
 
 
 
Basic
 
$
2.66

 
$
2.13

 
$
(1.08
)
 
$
(0.96
)
 
$
2.65

Diluted
 
$
2.64

 
$
2.11

 
$
(1.08
)