10-K 1 oas-12312017x10k.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 _______________________________________
FORM 10-K
 _______________________________________
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-34776
_______________________________________ 
Oasis Petroleum Inc.
(Exact name of registrant as specified in its charter)
_______________________________________
Delaware
 
80-0554627
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
1001 Fannin Street, Suite 1500
 
 
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)
(281) 404-9500
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Common Stock, par value $0.01 per share
 
New York Stock Exchange
(Title of Class)
 
(Name of 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  ý    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  ý 
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  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý   No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.  ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a 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
ý
Accelerated filer
¨
 
 
 
 
Non-accelerated filer
¨  (do not check if a smaller reporting company)
Smaller reporting company
¨
 
 
 
 
 
 
Emerging growth company
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨  No  ý
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $1,911,153,680
Number of shares of registrant’s common stock outstanding as of February 21, 2018: 317,595,983
_______________________________________ 
Documents Incorporated By Reference:
Portions of the registrant’s definitive proxy statement for its 2018 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2017, are incorporated by reference into Part III of this report for the year ended December 31, 2017.



OASIS PETROLEUM INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2017

TABLE OF CONTENTS
 
 
 
 
 
 
 
 
 
 
 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report on Form 10-K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” 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 statements about:
our business strategy;
estimated future net reserves and present value thereof;
timing and amount of future production of oil and natural gas;
drilling and completion of wells;
estimated inventory of wells remaining to be drilled and completed;
costs of exploiting and developing our properties and conducting other operations;
availability of drilling, completion and production equipment and materials;
availability of qualified personnel;
owning and operating a midstream company, including ownership interests in a master limited partnership;
owning and operating a well services company;
infrastructure for produced and flowback water gathering and disposal;
gathering, transportation and marketing of oil and natural gas, both in the Williston Basin and other regions in the United States;
property acquisitions, including our recent acquisition of oil and gas properties in the Delaware Basin;
integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;
the amount, nature and timing of capital expenditures;
availability and terms of capital;
our financial strategy, budget, projections, execution of business plan and operating results;
cash flows and liquidity;
oil and natural gas realized prices;
general economic conditions;
operating environment, including inclement weather conditions;
effectiveness of risk management activities;
competition in the oil and natural gas industry;
counterparty credit risk;
environmental liabilities;
governmental regulation and the taxation of the oil and natural gas industry;
developments in oil-producing and natural gas-producing countries;
technology;
uncertainty regarding future operating results; and
plans, objectives, expectations and intentions contained in this report that are not historical.
All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We disclaim any obligation to update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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PART I
Item 1. Business
Overview
Oasis Petroleum Inc. (together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. We are an independent exploration and production (“E&P”) company focused on the acquisition and development of onshore, unconventional oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) conducts our exploration and production activities and owns our proved and unproved oil and natural gas properties located in the North Dakota and Montana regions of the Williston Basin. We operate a midstream services business through OMS Holdings LLC (“OMS”), through which we own a majority of the outstanding units of Oasis Midstream Partners LP (NYSE: OMP) (“OMP” or “Oasis Midstream”), which completed its initial public offering on September 25, 2017. We also operate a well services business through Oasis Well Services LLC (“OWS”). Please see Note 16 to our Consolidated Financial Statements for more information regarding our business segments.
As of December 31, 2017, we have accumulated 502,660 net leasehold acres in the Williston Basin, of which approximately 95% is held by production. We are currently exploiting significant resource potential from the Bakken and Three Forks formations, which are present across a substantial portion of our acreage. We believe the location, size and concentration of our acreage create an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory. In addition, on February 14, 2018, we closed on an acquisition of approximately 22,000 net acres in the Delaware Basin, representing our initial entry into the Delaware Basin (the “Permian Basin Acquisition”). The Permian Basin Acquisition more than doubled our core net inventory and allows us to further capitalize on our operational strengths. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs, which we refer to as “resource conversion” opportunities, and has substantial Williston Basin and Delaware Basin experience.
In 2017, we completed and placed on production 88 gross operated wells in the Williston Basin and had average daily production of 66,144 Boe per day. As of December 31, 2017, we had 1,568 gross (819.4 net) producing wells in the Bakken and Three Forks formations. DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 312.2 MMBoe as of December 31, 2017, of which 64% were classified as proved developed and 72% were oil.
Our business strategy
Our goal is to enhance value by investing capital to build reserves, production and cash flows at attractive rates of return through the following strategies:
Efficiently develop our Williston Basin and Delaware Basin leasehold positions. We are developing our acreage positions to maximize the value of our resource potential, while maintaining flexibility to preserve future value when oil prices are low. During 2017, we completed and brought on production 88 gross (58.3 net) operated Bakken and Three Forks wells. As of December 31, 2017, we had 77 gross operated wells waiting on completion in the Bakken and Three Forks formations. Our 2018 capital plan contemplates completing and placing on production approximately 100 to 110 gross operated wells in the Williston Basin and approximately six to eight gross operated wells in the Delaware Basin. We have the ability to increase or decrease the number of wells drilled and the number of wells completed during 2018 based on market conditions and program results.
Enhance returns by focusing on operational and cost efficiencies. Our management team is focused on continuous improvement of our operations and has significant experience in successfully operating cost-efficient development programs. We believe the magnitude and concentration of our acreage within the Williston Basin, particularly in the core of the play, has provided and will continue to provide us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad into multiple formations, utilize centralized production and oil, gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization. The Permian Basin Acquisition enables us to transfer our technical, operational and managerial knowledge from full-field development of the Williston Basin to the Delaware Basin. In addition, we expect OMS and OWS to continue to provide operational synergies going forward compared to third party providers.
Adopt and employ leading drilling and completion techniques. Our team is focused on enhancing our drilling and completion techniques to maximize overall well economics. Completion techniques have significantly evolved over the past decade, resulting in increased initial production rates and recoverable hydrocarbons per well. High intensity completion techniques continue to deliver production performance greater than prior completion techniques. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve

4


our operating practices. This ongoing evolution may enhance our initial production rates, increase ultimate recovery factors, lower well capital costs and improve rates of return on invested capital.
Maintain financial flexibility. Based on current market conditions, we have a strong liquidity position. We have no short-term debt maturities, and as of December 31, 2017, we had $1,208.2 million of liquidity available, including $16.7 million of cash and cash equivalents and $1,191.5 million in the aggregate of unused borrowing base capacity available under our Revolving Credit Facilities (as defined in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources”). Our liquidity position, along with internally generated cash flows from operations, will provide continued financial flexibility as we actively manage the pace of development on our acreage positions in the Williston Basin and the Delaware Basin. We currently believe we have access to the public and private capital markets, and we intend to maintain a balanced capital structure by prudently raising proceeds from future offerings as additional capital needs arise. We also continue to evaluate options to monetize certain assets in our portfolio, which could result in increased liquidity and lower leverage.
Pursue strategic acquisitions with significant resource potential. As opportunities arise, we intend to identify and acquire additional acreage and producing assets to supplement our existing operations. On February 14, 2018, we completed the Permian Basin Acquisition, and going forward, we may acquire additional acreage in the Williston Basin and Delaware Basin or may selectively target additional basins that would allow us to employ our resource conversion strategy on large undeveloped acreage positions similar to what we have accumulated in the Williston Basin.
Our competitive strengths
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
Substantial leasehold position in one of North America’s leading unconventional oil-resource plays. We believe our Williston Basin acreage is one of the largest concentrated leasehold positions that is prospective in the Bakken and Three Forks formations. As of December 31, 2017, we had 502,660 net leasehold acres in the Williston Basin, of which 480,023 net acres were held by production, and 72% of our 312.2 MMBoe estimated net proved reserves in this area were comprised of oil. In 2018, we will continue our drilling and completion activities in the Williston Basin and will also begin operations in the Delaware Basin.
Large, multi-year project inventory. We believe we have a large inventory of potential drilling locations that we have not yet drilled, a majority of which are operated by us, and the Permian Basin Acquisition more than doubled our core net inventory. We plan to complete 100 to 110 gross operated wells with a working interest of approximately 73% in the Williston Basin and approximately six to eight gross operated wells with high working interest in the Delaware Basin in 2018.
Management team with proven operating and acquisition skills. Our senior management team has extensive expertise in the oil and gas industry with an average of more than 25 years of industry experience, including experience in multiple North American resource plays as well as experience in international basins. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, our technical team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs.
Incentivized management team. In 2017, an average of 70% of our executive officers’ overall compensation was in long-term equity-based incentive awards, and such officers owned over 3.5 million shares of our outstanding common stock as of December 31, 2017. We believe our executive officers’ ownership interest in us provides them with significant incentives to grow the value of our business for the benefit of all stakeholders.
Operating control over the majority of our portfolio. In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. As of December 31, 2017, 93% of our estimated net proved reserves were attributable to properties that we expect to operate. Approximately 93% of our 2017 drilling and completion capital expenditures and our 2018 plan are related to operated wells. Controlling operations will allow us to dictate the pace of development and better manage the costs, type and timing of exploration and development activities. We believe that maintaining operational control over the majority of our acreage will allow us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques. We are also better able to control infrastructure investment to drive down operating costs, optimize oil price realizations and increase the monetization of gas production.

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Vertical integration. Our investments in and operational control of OMS and OWS provide us with additional operational efficiencies and cost savings compared to our peers. This vertical integration helps us control capital dollars being spent in advance of production to ensure volumes flow, improve uptime performance of our producing wells, protect against rising service costs, increase transparency in the planning process and increase communications with vendors by purchasing directly from them.
Recent developments
Continuous Development Agreement
In connection with the closing of the Permian Basin Acquisition, Forge Energy, LLC (“Forge Energy”) entered into and assigned to Oasis Petroleum Permian LLC (“OP Permian”) a continuous development agreement with the Commissioner of the General Land Office, on behalf of the State of Texas (collectively, the “State”), as approved by the Board for Lease of University Lands (the “Board,” and together with the State, “University Lands”). This agreement concerns certain leases covering a substantial portion of the acreage that the Company indirectly acquired from Forge Energy in the Permian Basin Acquisition and under which University Lands is the lessor. Pursuant to this agreement, the tracts covered by these leases are pooled into a single development area for which the Company indirectly holds an eight year initial term ending on December 31, 2025, with an additional five year term for certain retained acreage at certain depths in the Delaware, Bone Springs and Wolfcamp formations. If OP Permian fails to meet certain drilling and development obligations, this agreement may be subject to early termination, in which case, the additional five year term would begin on such date and we may be obligated to pay non-performance fees of up to approximately $100 million.
Our operations
Proved reserves
Our estimated net proved reserves and related PV-10 at December 31, 2017, 2016 and 2015 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers. In preparing its reports, DeGolyer and MacNaughton evaluated 100% of the reserves and discounted values at December 31, 2017, 2016 and 2015 in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in oil and natural gas producing activities. Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure do not include probable or possible reserves and were determined using the preceding twelve months’ unweighted arithmetic average of the first-day-of-the-month index prices for oil and natural gas, which were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $51.34 per Bbl for oil and $2.99 per MMBtu for natural gas, $42.60 per Bbl for oil and $2.47 per MMBtu for natural gas and $50.16 per Bbl for oil and $2.63 per MMBtu for natural gas for the years ended December 31, 2017, 2016 and 2015, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The information in the following table does not give any effect to or reflect our commodity derivatives. Future operating costs, production taxes and capital costs were based on current costs as of each year-end. For a definition of proved reserves under the SEC rules, please see the “Glossary of oil and natural gas terms” included at the end of this report. For more information regarding our independent reserve engineers, please see “Independent petroleum engineers” below. Future net revenues represent projected revenues from the sale of our estimated net proved reserves (excluding derivative contracts) net of production and development costs (including operating expenses and production taxes). PV-10 and Standardized Measure represent the present value of the future net revenues discounted at 10%, before and after income taxes, respectively.
There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimates for the same properties. There can be no assurance that our estimated net proved reserves will be produced within the periods indicated or that prices and costs will remain constant. A substantial or extended decline in oil prices could result in a significant decrease in our estimated net proved reserves and related future net revenues, Standardized Measure and PV-10 in the future.

6


The following table summarizes our estimated net proved reserves and related future net revenues, Standardized Measure and PV-10:
 
At December 31,
 
2017
 
2016
 
2015
Estimated proved reserves:
 
 
 
 
 
Oil (MMBbls)
225.0

 
236.6

 
184.9

Natural gas (Bcf)
523.5

 
411.1

 
199.8

Total estimated proved reserves (MMBoe)
312.2

 
305.1

 
218.2

Percent oil
72
%
 
78
%
 
85
%
Estimated proved developed reserves:
 
 
 
 
 
Oil (MMBbls)
150.6

 
152.3

 
127.4

Natural gas (Bcf)
301.1

 
229.6

 
120.8

Total estimated proved developed reserves (MMBoe)
200.8

 
190.6

 
147.6

Percent proved developed
64
%
 
62
%
 
68
%
Estimated proved undeveloped reserves:
 
 
 
 
 
Oil (MMBbls)
74.3

 
84.3

 
57.5

Natural gas (Bcf)
222.4

 
181.5

 
79.0

Total estimated proved undeveloped reserves (MMBoe)
111.4

 
114.5

 
70.7

Future net revenues (in millions)
$
6,185.4

 
$
4,645.6

 
$
3,827.9

Standardized Measure (in millions)(1)
$
3,300.7

 
$
2,483.1

 
$
1,914.3

PV-10 (in millions)(2)
$
3,683.7

 
$
2,627.8

 
$
2,022.7

__________________ 
(1)
Standardized Measure represents the present value of estimated future net cash flows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.
(2)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under accounting principles generally accepted in the United States of America (“GAAP”), because it does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas reserves. The oil and gas industry uses 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. See “Reconciliation of PV-10 to Standardized Measure” below.
Estimated net proved reserves at December 31, 2017 were 312.2 MMBoe, a 2% increase from estimated net proved reserves of 305.1 MMBoe at December 31, 2016 primarily due to an increase of 51.2 MMBoe for additions, partially offset by a decrease of 24.1 MMBoe for production and net negative revisions of 19.2 MMBoe. This net negative revision was attributable to negative revisions of 39.1 MMBoe due to well performance and 2.1 MMBoe for alignment to the anticipated five-year development plan, offset by positive revisions of 16.1 MMBoe due to higher realized prices and 2.5 MMBoe for ownership adjustments. Our proved developed reserves increased 10.2 MMBoe, or 5%, to 200.8 MMBoe for the year ended December 31, 2017 from 190.6 MMBoe for the year ended December 31, 2016, primarily due to our 2017 development program, which included 153 gross (63.0 net) wells that were completed and brought on production during 2017 and resulted in additions of 17.9 MMBoe and conversions of 32.0 MMBoe. These increases were partially offset by a decrease of 24.1 MMBoe for production and negative revisions of 14.2 MMBoe. Proved developed revisions were primarily due to a negative revision of 29.7 MMBoe for performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, offset by a positive revision of 14.1 MMBoe from increased realized prices. Our proved undeveloped reserves decreased to 111.4 MMBoe for the year ended December 31, 2017 from 114.5 MMBoe for the year ended December 31, 2016 due to the conversion of wells to proved developed of 32.0 MMBoe and negative revisions of 5.0 MMBoe, partially offset by 33.3 MMBoe of additions. The proved undeveloped revisions were primarily due a negative revision of 9.4 MMBoe for performance revisions largely related to the associated impact of higher than anticipated decline rates in recently developed spacing units and a negative 1.8 MMBoe revision associated with alignment to the five-year development plan, offset by a positive revision of 2.6 MMBoe for ownership adjustments and 2.0 MMBoe from increased realized prices. In 2017, the Company divested 1.4 MMBoe of reserves associated with reservoirs other than the Bakken or Three Forks formations.

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Estimated net proved reserves at December 31, 2016 were 305.1 MMBoe, a 40% increase from estimated net proved reserves of 218.2 MMBoe at December 31, 2015 primarily due to acquisitions and revisions, partially offset by lower commodity prices and the 2016 divestiture of certain legacy wells that were producing from conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations. The proved reserves net positive revision of 31.1 MMBoe was attributable to positive revisions of 30.4 MMBoe due to well performance and larger completion designs, 8.2 MMBoe due to higher gas to oil ratio and 8.2 MMBoe due to ownership adjustments, offset by 9.5 MMBoe due to the removal of proved undeveloped reserves that were no longer aligned with the Company’s anticipated five-year development plan and 8.2 MMBoe due to lower commodity prices. Our proved developed reserves increased 43.0 MMBoe, or 29%, to 190.6 MMBoe for the year ended December 31, 2016 from 147.6 MMBoe for the year ended December 31, 2015, primarily due to acquisitions and our 2016 development program, including the completion of 57 gross (37.6 net) operated wells, partially offset by production and 6.6 MMBoe due to higher abandonment rates resulting from lower commodity price assumptions. Our proved undeveloped reserves increased to 114.5 MMBoe for the year ended December 31, 2016 from 70.7 MMBoe for the year ended December 31, 2015 due to acquisitions and positive revisions related to larger completion designs of 27.6 MMBoe, partially offset by conversions of wells to proved developed as a result of our 2016 development program and 9.5 MMBoe for the removal of proved undeveloped reserves that are no longer aligned with our anticipated five-year development plan as of December 31, 2016.
Reconciliation of Standardized Measure to PV-10
PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.
The following table provides a reconciliation of the Standardized Measure of discounted future net cash flows to PV-10:
 
At December 31,
 
2017
 
2016
 
2015
 
 
 
(In millions)
 
 
Standardized Measure of discounted future net cash flows
$
3,300.7

 
$
2,483.1

 
$
1,914.3

Add: present value of future income taxes discounted at 10%
383.0

 
144.7

 
108.4

PV-10
$
3,683.7

 
$
2,627.8

 
$
2,022.7

The PV-10 of our estimated net proved reserves at December 31, 2017 was $3,683.7 million, a 40% increase from PV-10 of $2,627.8 million at December 31, 2016. This increase was primarily due to higher commodity price assumptions and an increase in reserves year over year.
Proved undeveloped reserves
At December 31, 2017, we had approximately 111.4 MMBoe of proved undeveloped reserves as compared to 114.5 MMBoe at December 31, 2016.

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The following table summarizes the changes in our proved undeveloped reserves during 2017:
 
Year Ended
December 31, 2017
 
(in MBoe)
Proved undeveloped reserves, beginning of period
114,512

Extensions, discoveries and other additions
33,284

Purchases of minerals in place
619

Sales of minerals in place

Revisions of previous estimates
(5,004
)
Conversion to proved developed reserves
(32,019
)
Proved undeveloped reserves, end of period
111,392

During 2017, we spent a total of $304.9 million related to the development of proved undeveloped reserves, $102.3 million of which was spent on proved undeveloped reserves that represent wells in progress at year-end. The remaining $202.6 million resulted in the conversion of 32.0 MMBoe of proved undeveloped reserves, or 28% of our proved undeveloped reserves balance at the beginning of 2017, to proved developed reserves. We participated in 153 gross (63.0 net) wells that were completed and brought on production during 2017. We added 33.3 MMBoe of proved undeveloped reserves in the Williston Basin as a result of our five-year development plan. The 2017 proved undeveloped revision of negative 5.0 MMBoe is primarily due to a decrease of 9.4 MMBoe for performance revisions primarily related to higher than anticipated decline rates observed in recent development and a decrease of 1.8 MMBoe for the alignment with the five-year development plan, offset by an increase of 2.6 MMBoe for ownership adjustments and 2.0 MMBoe for higher realized prices.
We expect to develop all of our proved undeveloped reserves, including all wells drilled but not yet completed, as of December 31, 2017 within five years after the initial year booked. The future development of such proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such as capital markets, our Revolving Credit Facilities, and our derivative contracts. All proved undeveloped locations are located on properties where the leases are held by existing production or continuous drilling operations. Approximately 22% of our proved undeveloped reserves at December 31, 2017 are attributable to wells that have been drilled but not yet completed, and 100% of our undrilled reserves are within our core acreage in the Williston Basin.
Independent petroleum engineers
Our estimated net proved reserves and related future net revenues and PV-10 at December 31, 2017, 2016 and 2015 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007) and definitions and current guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Moscow and Algiers. The firm’s more than 200 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton has provided such services for over 80 years. The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Professional Engineer in the State of Texas with over 30 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from The University of Texas at Austin in 1984, and he is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.
Technology used to establish proved reserves
In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of 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. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically,

9


there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007). The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
Based on the current stage of field development, production performance, the development plans provided by us to DeGolyer and MacNaughton and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production decline curves, reserves were estimated only to the limits of economic production.
Undeveloped reserves were estimated for locations adjacent to existing wells and are based on consideration of lateral length, completion and production profiles compared by appropriate target reservoir. In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data was available.
Internal controls over reserves estimation process
We employ DeGolyer and MacNaughton as the independent reserves evaluator for 100% of our reserves base. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process. Brett Newton, Senior Vice President of Asset Management and Chief Engineer, is the technical person primarily responsible for overseeing our reserves evaluation process. He has over 25 years of industry experience with positions of increasing responsibility in engineering and management. He holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering. Mr. Newton reports directly to our President and Chief Operating Officer.
Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following:
Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database;
Review of working interests and net revenue interests in our reserves database against our well ownership system;
Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database;
Review of updated capital costs prepared by our operations team;
Review of internal reserve estimates by well and by area by our internal reservoir engineers;
Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President of Asset Management and Chief Engineer;
Review of a preliminary copy of the reserve report by our President and Chief Operating Officer with our internal technical staff; and
Review of our reserves estimation process by our Audit Committee on an annual basis.
Production, revenues and price history
We produce and market oil and natural gas, which are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Oil supply in the United States has grown dramatically over the past several years, putting

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downward pressure on oil prices. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil and natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets. Please see “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessA substantial or extended decline in commodity prices, in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”
The following table sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated. For additional information on price calculations, please see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
Year Ended December 31,
 
2017
 
2016
 
2015
Net production volumes:
 
 
 
 
 
Oil (MBbls)
18,818

 
15,174

 
16,091

Natural gas (MMcf)
31,946

 
19,573

 
14,002

Oil equivalents (MBoe)
24,143

 
18,436

 
18,424

Average daily production (Boe per day)
66,144

 
50,372

 
50,477

Average sales prices:
 
 
 
 
 
Oil, without derivative settlements (per Bbl)
$
48.52

 
$
38.64

 
$
43.04

Oil, with derivative settlements (per Bbl)(1)
48.00

 
46.68

 
66.06

Natural gas, without derivative settlements (per Mcf)(2)
3.81

 
1.99

 
2.08

Natural gas, with derivative settlements (per Mcf)(1)(2)
3.86

 
1.99

 
2.08

Costs and expenses (per Boe of production):
 
 
 
 
 
Lease operating expenses
$
7.34

 
$
7.35

 
$
7.84

Marketing, transportation and gathering expenses(3)
2.31

 
1.63

 
1.72

Production taxes
3.65

 
3.07

 
3.78

Depreciation, depletion and amortization
21.99

 
25.84

 
26.34

General and administrative expenses(4)
3.80

 
4.85

 
4.86

__________________ 
(1)
Realized prices include gains or losses on cash settlements for our commodity derivatives, which do not qualify for or were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)
Natural gas prices include the value for natural gas and natural gas liquids.
(3)
Prior to the first quarter of 2017, marketing, transportation and gathering expenses included purchased oil and gas expenses, which represent the crude oil purchased primarily for blending at our crude oil terminal. Prior periods have been adjusted retrospectively to reflect these expenses in purchased oil and gas expenses on our Consolidated Statements of Operations. For the year ended December 31, 2016, marketing, transportation and gathering expenses have been adjusted to exclude $10.3 million of purchased oil and gas expenses.
(4)
For the year ended December 31, 2017, certain well services direct field labor compensation expenses are included in well services operating expenses on our Consolidated Statements of Operations, which were previously recognized in general and administrative expenses on our Consolidated Statements of Operations. For the years ended December 31, 2016 and 2015, well services operating expenses have been adjusted to include $2.9 million and $3.7 million, respectively, which were previously recognized in general and administrative expenses on our Consolidated Statements of Operations.
Net production volumes for the year ended December 31, 2017 were 24,143 MBoe as compared to net production of 18,436 MBoe for the year ended December 31, 2016. Our net production volumes increased from 2016 to 2017 primarily due to our acquisition of producing properties in December 2016 and a successful operated and non-operated drilling and completion program, offset by the natural decline in production in wells that were producing as of December 31, 2016. Average oil sales prices, without derivative settlements, increased by $9.88 per barrel, or 26%, to an average of $48.52 per barrel for the year ended December 31, 2017 as compared to the year ended December 31, 2016. Giving effect to our derivative transactions in both periods, our oil sales prices increased $1.32 per barrel to $48.00 per barrel for the year ended December 31, 2017 from $46.68 per barrel for the year ended December 31, 2016.

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Net production volumes for the year ended December 31, 2016 were 18,436 MBoe as compared to net production of 18,424 MBoe for the year ended December 31, 2015. Our net production volumes remained relatively consistent from 2015 to 2016 primarily due to a successful operated and non-operated drilling and completion program and our acquisition of producing properties in December 2016, offset by the natural decline in production in wells that were producing as of December 31, 2015. Average oil sales prices, without derivative settlements, decreased by $4.40 per barrel, or 10%, to an average of $38.64 per barrel for the year ended December 31, 2016 as compared to the year ended December 31, 2015. Giving effect to our derivative transactions in both periods, our oil sales prices decreased $19.38 per barrel to $46.68 per barrel for the year ended December 31, 2016 from $66.06 per barrel for the year ended December 31, 2015.
Productive wells
The following table presents the total and operated gross and net productive wells as of December 31, 2017:
 
Total wells
 
Operated wells
 
Gross
 
Net
 
Gross
 
Net
Bakken and Three Forks
1,568

 
819.4

 
996

 
751.2

Other
2

 
2.0

 
2

 
2.0

Total wells
1,570

 
821.4

 
998

 
753.2

All of our productive wells are oil wells. Gross wells are the number of wells, operated and non-operated, in which we own a working interest and net wells are the total of our working interests owned in gross wells.
Acreage
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2017. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
 
Gross
 
Net
Developed acres
555,889

 
412,849

Undeveloped acres
146,505

 
89,811

Total acres
702,394

 
502,660

Our acreage that is held by production decreased to 480,023 net acres at December 31, 2017 from 484,321 net acres at December 31, 2016.
Undeveloped acreage
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2017 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates:
 
Undeveloped acres expiring
 
Gross
 
Net
Year ending December 31,
 
 
 
2018
11,005

 
8,163

2019
2,720

 
2,640

2020
12,792

 
7,244


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Drilling and completion activity
The following table summarizes our completion activity for the years ended December 31, 2017, 2016 and 2015. Gross wells reflect the sum of all productive and dry wells, operated and non-operated, in which we own a working interest. Net wells reflect the sum of our working interests in gross wells. The gross and net wells represent wells completed during the periods presented, regardless of when drilling was initiated.
 
Year ended December 31,
 
2017
 
2016
 
2015
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development wells:
 
 
 
 
 
 
 
 
 
 
 
Oil
153

 
63.0

 
64

 
38.1

 
115

 
59.1

Gas

 

 

 

 

 

Dry

 

 

 

 

 

Total development wells
153

 
63.0

 
64

 
38.1

 
115

 
59.1

Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
Oil

 

 

 

 
6

 
5.2

Gas

 

 

 

 

 

Dry

 

 

 

 

 

Total exploratory wells

 

 

 

 
6

 
5.2

Total wells
153

 
63.0

 
64

 
38.1

 
121

 
64.3

Over the past several years, we have focused on full field development and have concentrated on improving capital efficiency and completing more wells using high-intensity completion techniques. We also continued to participate in a number of wells on a non-operated basis.
We did not drill any dry hole wells in 2017, 2016 or 2015.
As of December 31, 2017, we had five operated rigs running, 4 gross (2.5 net) operated wells drilling and an inventory of 77 gross operated wells waiting on completion. We expect to continue to concentrate drilling activities within our core acreage in 2018, including in the Bakken and Three Forks formations in the Williston Basin as well as on our recently acquired Delaware Basin acreage.
Capital expenditures
In 2017, we spent $836.2 million on capital expenditures, which represented a 29% decrease as compared to the $1,181.5 million spent during 2016. Excluding acquisitions of $54.0 million in 2017, which includes the deposit of $47.3 million paid as part of the Permian Basin Acquisition, and $781.5 million in 2016, our capital expenditures increased 96% to $782.2 million from the $400.0 million spent during 2016. This increase was primarily due to increased drilling and completion activity as a result of higher commodity prices in 2017 coupled with higher capital expenditures for OMS primarily related to the construction of midstream infrastructure, including a second natural gas processing plant in our Wild Basin area in North Dakota, and higher capital expenditures for OWS related to adding a second fracturing fleet. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources—Cash flows used in investing activities.”
We have increased our planned 2018 capital expenditures as compared to 2017, excluding acquisitions, as a result of current commodity prices. Our total 2018 capital expenditure plan is approximately $1,090 million to $1,170 million, which includes approximately $815 million to $855 million for E&P capital expenditures, including approximately $700 million to $730 million focused in the Williston Basin and approximately $115 million to $125 million focused in the Delaware Basin (with approximately 91% of the E&P capital allocated to drilling and completions), approximately $235 million to $275 million for infrastructure and midstream capital expenditures and approximately $40 million of other capital expenditures, including capitalized interest, well services equipment and administrative capital. We plan to complete and place on production approximately 100 to 110 gross operated wells in the Williston Basin and approximately six to eight gross operated wells in the Delaware Basin in 2018.
While we have budgeted approximately $1,090 million to $1,170 million in 2018 for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Additionally, if we acquire additional acreage, our capital expenditures may be higher than budgeted. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources.”

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Description of properties
As of December 31, 2017, our operations were focused in the North Dakota and Montana areas of the Williston Basin. Our development activities are currently concentrated in the Bakken and Three Forks formations. Our management team originally targeted the Williston Basin because of its oil-prone nature, multiple producing horizons, substantial resource potential and management’s previous professional history in the basin. The Williston Basin also generally has established infrastructure and access to materials and services. Our development activity is focused in the deepest part of the Williston Basin, which we call the core.
As of December 31, 2017, our total leasehold position in the Williston Basin consisted of 502,660 net acres, and our estimated net proved reserves in the Williston Basin were 312.2 MMBoe, of which 200.8 MMBoe were proved developed reserves and 111.4 MMBoe were proved undeveloped reserves. As of December 31, 2017, we had a total of 821.4 net operated and non-operated producing wells and 753.2 net operated producing wells in the Williston Basin. We had average daily production of 66,144 net Boe per day for the year ended December 31, 2017 in the Williston Basin. During 2017, our Bakken and Three Forks wells produced a daily average of 65,636 net Boe per day with 819.4 net producing wells on December 31, 2017. Accordingly, our 819.4 net Bakken and Three Forks wells were responsible for nearly 99% of our average daily production during 2017. As of December 31, 2017, our working interest for all producing wells averaged 52% and in the wells we operate averaged 75%. As of December 31, 2017, we had 112 gross (59.4 net) wells in the process of being drilled or completed in the Williston Basin, which includes 4 gross operated wells drilling, 77 gross operated wells waiting on completion and 31 gross non-operated wells drilling or completing. We participated in 153 gross (63.0 net) wells that were completed and brought on production during 2017.
On December 11, 2017, we entered into a Purchase and Sale Agreement with Forge Energy to acquire approximately 22,000 net acres in the Delaware Basin. The Permian Basin Acquisition represents our initial entry into the Delaware Basin. The assets underlying the Permian Basin Acquisition are primarily located in the Bone Spring and Wolfcamp formations of the Delaware sub-basin, across Ward, Winkler, Loving and Reeves Counties, Texas.
Marketing, transportation and major customers
The Williston Basin crude oil rail and pipeline transportation and refining infrastructure has grown substantially over the past decade, largely in response to drilling activity in the Bakken and Three Forks formations. In December 2017, oil production in North Dakota was approximately 1,181,000 barrels per day. According to the North Dakota Pipeline Authority website’s data last updated January 19, 2018, there was approximately 1,371,000 barrels per day of crude oil pipeline transportation capacity and approximately 1,520,000 barrels per day of specifically dedicated rail loading capacity in the Williston Basin as of December 31, 2017. In 2017, we continued to sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which typically originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. As of December 31, 2017, we were flowing approximately 90% of our gross operated oil production through these gathering systems.
Crude oil produced and sold in the Williston Basin has historically sold at a discount to the NYMEX West Texas Intermediate crude oil index price (“WTI”) due to transportation costs and takeaway capacity. In the past, there have been periods when this discount has substantially increased due to the production of oil in the area increasing to a point that it temporarily surpasses the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on oil transportation out of the Williston Basin and improved netback pricing received at the lease. In 2015, our price differentials relative to WTI strengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail gradually declined. Since the third quarter of 2015, our price differentials have averaged less than $5.00 per barrel discount to WTI. In the second half of 2017, our crude oil price differentials improved to less than $2.00 per barrel primarily due to the additional takeaway capacity of the Dakota Access Pipeline of over 450,000 barrels per day. Our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. For a discussion of the potential risks to our business that could result from transportation and refining infrastructure constraints in the Williston Basin, please see “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessInsufficient transportation or refining capacity in the Williston Basin and Delaware Basin could cause significant fluctuations in our realized oil and natural gas prices.”
We principally sell our oil and natural gas production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, please see “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessMarket conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production” and “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessInsufficient transportation or refining capacity in the Williston Basin and Delaware Basin could cause significant fluctuations in our realized oil and natural gas prices.”

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In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. As of December 31, 2017, we sold a substantial majority of our oil and condensate through bulk sales at delivery points on crude oil gathering systems or directly at the wellhead to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market-based price, which incorporates regional differentials that include, but are not limited to, transportation costs and adjustments for product quality. We also entered into various short-term sales contracts for a portion of our portfolio at fixed differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows.
For the year ended December 31, 2017, sales to Shell Trading (US) Company accounted for approximately 16% of our total sales. For the year ended December 31, 2016, sales to PBF Holding Company LLC accounted for approximately 10% of our total sales. For the year ended December 31, 2015, sales to Shell Trading (US) Company accounted for approximately 10% of our total sales. No other purchasers accounted for more than 10% of our total oil and natural gas sales for the years ended December 31, 2017, 2016 and 2015. We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are a number of alternative crude oil and natural gas purchasers in the Williston Basin.
Since most of our oil and natural gas production is sold under market-based or spot market contracts, the revenues generated by our operations are highly dependent upon the prices of and demand for oil and natural gas. The price we receive for our oil and natural gas production depends upon numerous factors beyond our control, including but not limited to seasonality, weather, competition, availability of transportation and gathering capabilities, worldwide and regional economic conditions, global and domestic oil supply, foreign imports, political conditions in other oil-producing and natural gas-producing regions, the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and domestic government regulation, legislation and policies. Please see “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessA substantial or extended decline in commodity prices, in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.” Furthermore, a decrease in the price of oil and natural gas could have an adverse effect on the carrying value of our estimated proved reserves and on our revenues, profitability and cash flows. Please see “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessIf oil and natural gas prices decline substantially or for an extended period of time from their current levels, we may be required to take write-downs of the carrying values of our oil and natural gas properties.”
Market, economic, transportation and regulatory factors may in the future materially affect our ability to market our oil or natural gas production. Please see “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessMarket conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.”
Competition
The oil and natural gas industry is worldwide and highly competitive in all phases. We encounter competition from other oil and natural gas companies in all areas of operation, including the acquisition of leasing options on oil and natural gas properties to the exploration and development of those properties. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Such companies may be able to pay more for lease options on oil and natural gas properties and exploratory locations and to define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Please see “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessCompetition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.”
Title to properties
As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with general industry standards. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the

15


properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our Revolving Credit Facilities, liens for current taxes and other burdens, which we believe do not materially interfere with the use or affect our carrying value of the properties. Please see “Item 1A. Risk FactorsRisks related to the oil and natural gas industry and our businessWe may incur losses as a result of title defects in the properties in which we invest.”
Seasonality
Winter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.
Regulation of the oil and natural gas industry
Our producing, midstream and well services operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production, oil gathering and transportation, natural gas processing and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production or otherwise provide midstream services have statutory provisions regulating the exploration for and production of oil and natural gas or the gathering, transportation and processing of those commodities, including provisions related to permits for the drilling of wells or processing of natural gas, bonding requirements to drill or operate producing or injection wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled or processing plants are constructed, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, the siting of processing plants, disposal wells and gathering or transportation lines, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs with applicable laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations; however, there can be no assurance that such costs will not be material in the future as these laws and regulations are subject to amendment or reinterpretation. Additionally, environmental incidents such as spills or other releases may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.
Regulation of transportation and sales of oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of service filing. Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs. Most recently, on December 17, 2015, FERC established a new price index for the five-year period beginning July 1, 2016.
On December 22, 2017, the President signed into law Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, following its passage by the U.S. Congress. The Tax Cuts and Jobs Act made significant changes to U.S. federal income tax laws, including a reduction in the maximum corporate tax rate. Following the enactment of the Tax Cuts and Jobs Act, filings have been made at FERC requesting that FERC require pipelines to lower their transportation rates to account for the reduction in the corporate tax rate. FERC may enact regulations or issue requests to pipelines regarding the impact of the corporate tax rate change on the transportation rates. However, FERC’s establishment of a just and reasonable rate is based on many components, and the reduction in the corporate tax rate may only impact two of such components, the allowance for

16


income taxes and the amount for accumulated deferred income taxes. Because our existing jurisdictional rates were established based on a higher corporate tax rate, FERC or our shippers may challenge these rates in the future, and the resulting new rate may be lower than the rates we currently charge.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
We sell a significant amount of our crude oil production through gathering systems connected to rail facilities. Several derailments of freight trains have led transportation safety regulators in the United States and Canada to examine whether the hazardous nature of crude oil from the Bakken shale is being assessed properly prior to its shipment. In particular, there are concerns that the testing and ensuing designations of crude oil on the shipping documentation do not in all cases accurately capture the flammability of the Bakken shale crude oil. In January 2014, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) released a Safety Alert alerting regulators, emergency responders, transporters and shippers that crude oil from the Bakken shale may have flammability characteristics that are different from other forms of crude oil and that it was vital that all shipments of crude oil be tested and properly characterized on all shipping documentation. The Safety Alert also notified the regulated community that PHMSA and the Federal Railroad Administration (“FRA”) had launched an enforcement initiative that involved unannounced inspections on crude oil shipments to test the contents of the shipments in order to ensure that they are properly characterized. In August 2014, the U.S. Department of Transportation released a report finding that, based on the results of this enforcement initiative from August 2013 to May 2014, Bakken shale crude oil tended to be more volatile and flammable than other crude oils, and thus posed an increased risk for a significant accident.
These events have also spurred efforts to improve the safety of tank cars that are used in transporting crude oil by rail. Since 2011, all new railroad tank cars that have been built to transport crude oil or other petroleum type fluids, including ethanol, have been built to more stringent safety standards. In May 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, and a requirement that older DOT-111 tank cars be phased out by as early as January 1, 2018 if they are not already retrofitted to comply with new tank car design standards. The rule also includes a new braking standard for certain trains, designates new operational protocols for trains transporting large volumes of flammable liquids, such as routing analyses, speed restrictions and information for local government agencies, and provides new sampling and testing requirements to improve classification of energy products placed into transport. On December 13, 2017, PHMSA announced that it would initiate a rulemaking to rescind the May 2015 rule’s requirements regarding electronically controlled pneumatic brakes. In August 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029. Additionally, in July 2016, PHMSA proposed a new rule that would expand the applicability of comprehensive oil spill response plans so that any railroad that transports a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train must have a current, comprehensive, written plan. PHMSA has not yet issued a final version of the rule. In response to a petition from the New York Attorney General, PHMSA issued an advance notice of proposed rulemaking (“ANPR”) in January 2017 stating that it is considering revising the Hazardous Materials Regulations to establish vapor pressure limits for unrefined petroleum-based products and potentially all Class 3 flammable liquid hazardous materials that would apply during the transportation of the products or materials by any mode. PHMSA has not yet issued a final version of the rule. In addition, in February 2016, the FRA modified its accident and incident reports to gather additional data concerning rail cars carrying crude oil in any train involved in an FRA-reportable accident. In addition to action taken or proposed by federal agencies, a number of states proposed or enacted laws in recent years that encourage safer rail operations or urge the federal government to strengthen requirements for these operations.
Safety improvements or updates to existing tank cars that are imposed under the May 2015 PHMSA requirements could drive up the cost of transport and lead to shortages in availability of tank cars. We do not currently own or operate rail transportation facilities or rail cars; however, we cannot assure that costs incurred by the railroad industry to comply with these enhanced standards resulting from PHMSA’s final rule will not increase our costs of doing business or limit our ability to transport and sell our crude oil at favorable prices, the consequences of which could be material to our business, financial condition or results of operations. However, we believe that any such consequences would not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

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Efforts are likewise underway in Canada to assess and address risks from the transport of crude oil by rail. For example, in April 2014, Transport Canada issued a protective order prohibiting oil shippers from using 5,000 of the DOT-111 tank cars and imposing a three year phase out period for approximately 65,000 tank cars that do not meet certain safety requirements. Transport Canada also imposed a 50 mile per hour speed limit on trains carrying hazardous materials and required all crude oil shipments in Canada to have an emergency response plan. At the same time that PHMSA released its 2015 rule, Canada’s Minister of Transport announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule. Likewise, Transport Canada’s rail car retrofitting and phase out timeline largely aligns with the timeline introduced under the 2015 and 2016 PHMSA rules. Transport Canada has also introduced new requirements that railways carry minimum levels of insurance depending on the quantity of crude oil or dangerous goods that they transport as well as a final report recommending additional practices for the transportation of dangerous goods.
Historically, our hazardous materials transportation compliance costs have not had a material adverse effect on our results of operations; however, these, and future laws, regulatory changes, or initiatives regarding hazardous material transportation, could directly and indirectly increase our operation, compliance and transportation costs and lead to shortages in availability of tank cars. We cannot assure that costs incurred to comply with standards and regulations emerging from these and future rulemakings will not be material to our business, financial condition or results of operations. Moreover, we may incur significant constraints on transportation capacity during the period while tank cars are being retrofitted or newly constructed to comply with the new regulations. In addition, any derailment of crude oil from the Bakken shale involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event. Nonetheless, we believe that any such consequences would not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Regulation of transportation and sales of natural gas
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC under Order No. 637 will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission (“CFTC”) and the Federal Trade Commission (“FTC”). Please see below the discussion of “Other federal laws and regulations affecting our industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information

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regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC market transparency rules.”
Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case by case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own and operate properties in North Dakota and Montana, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, both states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Other federal laws and regulations affecting our industry
Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (“EPAct 2005”). EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1,238,271 per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,238,271 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, as described below. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

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FERC market transparency rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.
Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1,180,566 per day per violation, in addition to any applicable penalty under the Federal Trade Commission Act.
North Dakota Industrial Commission oil and natural gas rules. The North Dakota Industrial Commission (“NDIC”) regulates the drilling and production of oil and natural gas in North Dakota. Beginning in 2012, the NDIC has adopted more stringent rule changes to its existing oil and natural gas regulations, imposing relatively higher bonding amounts for the drilling of wells, severely restricting the discharge and storage of production wastes such as produced water, drilling mud, waste oil and other wastes in earthen pits, implementing more stringent hydraulic fracturing requirements and requiring the provision of public disclosure on the national website, FracFocus.org, regarding chemicals used in the hydraulic fracturing process. During 2016, the NDIC approved a suite of additional rules for the conservation of crude oil and natural gas. Requirements relating to site construction, underground gathering pipelines and spill containment became effective in 2016 while other requirements relating to bonding requirements for underground gathering pipelines, and construction of berms around facilities became effective on in 2017. Responding to these recent rule changes by oil and natural gas E&P operators in general, and us in particular, increased our well costs from 2012 to 2017, and we expect to continue to incur these increased costs in order to respond to current requirements.
Furthermore, in 2014, the NDIC adopted an order intended to reduce natural gas flaring, which order was subsequently modified in late 2015. Please see below the discussion of “Environmental protection and natural gas flaring initiatives” for more information on this order. In addition, in 2014, the NDIC adopted conditioning standards that are now in effect and improve the safety of Bakken crude oil for transport. The rule sets operating standards for conditioning equipment to properly separate production fluids and includes parameters for temperatures and pressures for production equipment. The rule also addresses limits to vapor pressure of produced crude oil.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
Pipeline safety regulation
Certain of our pipelines are subject to regulation by PHMSA under the Hazardous Liquids Pipeline Safety Act (“HLPSA”) with respect to oil and condensates and the Natural Gas Pipeline Safety Act (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of oil and natural gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas (“HCAs”), such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. New laws or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

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The HLPSA and NGPSA were amended by the Pipeline, Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), which became law in January 2012. The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. In June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “2016 Pipeline Safety Act “) was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property or the environment.
The adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on our results of operations. For example, in January 2017, PHMSA issued a final rule that significantly extends and expands the reach of certain PHMSA hazardous liquid pipeline integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a HCA. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register remains uncertain following the January 2017 change in Presidential Administrations. In a second example, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as five dwellings within a potential impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has not yet finalized the March 2016 proposed rulemaking. New laws or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In the absence of the PHMSA pursuing any legal requirements, state agencies, to the extent authorized, may pursue state standards, including standards for rural gathering lines.
Environmental and occupational health and safety regulation
Our exploration, development and production operations, oil gathering and transportation activities, natural gas processing services and related operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct drilling or provide midstream services; govern the amounts and types of substances that may be released into the environment; limit or prohibit construction or drilling activities in environmentally-sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered species; require investigatory and remedial actions to mitigate pollution conditions; impose obligations to reclaim and abandon well sites, pits, processing plants and pipelines; and impose specific criteria addressing worker protection. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of delays in the permitting or development or expansion of projects and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in federal or state environmental laws and regulations or reinterpretation of applicable enforcement policies that result in more stringent and costly well construction, drilling, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental spills or other releases may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such spills or releases, including any third-party claims for damage to property, natural resources or persons. While, historically, our compliance costs with environmental laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations, there can be no assurance that such costs

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will not be material in the future as a result of such existing laws and regulations or any new laws and regulations, or that such future compliance will not have a material adverse effect on our business and operating results.
The following is a summary of the more significant existing environmental and occupational health and safety laws, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous substances and wastes
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These classes of persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.
We are also subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation, disposal and cleanup of hazardous and nonhazardous wastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate ordinary industrial wastes that may be regulated as hazardous wastes. RCRA currently exempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of oil and natural gas from regulation as hazardous wastes. These wastes, instead, are regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as nonhazardous wastes could be classified as hazardous wastes in the future. For example, in response to a lawsuit filed in the U.S. District Court for the District of Columbia by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court in December 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Repeal or modification of the current RCRA exclusion or similar exemptions under state law could increase the amount of hazardous waste we are required to manage and dispose of and could cause us or our customers to incur increased operating costs, which could have a significant impact on us as well as reduce demand for our midstream services.
We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas or for conducting midstream services. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons, hazardous substances and wastes may have been released on, under or from the properties owned or leased by us or on, under or from, other locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes were not under our control. These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial plugging or pit, processing plant or pipeline closure operations to prevent future contamination.
Air emissions
The federal Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of various air pollutants from many sources through air emissions standards, construction and operating permitting programs, and the imposition of other monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of

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certain pollutants. Obtaining permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion under both the primary and secondary standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the U.S. not addressed under the November 2017 final rule in the first half of 2018. Additionally, state implementation of these revised standards 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. Compliance with this final rule or any other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, significantly increase our capital expenditures and operating costs, and reduce demand for the oil and natural gas that we produce, which one or more developments could adversely impact our business.
Environmental protection and natural gas flaring initiatives
We attempt to conduct our operations in a manner that protects the health, safety and welfare of the public, our employees and the environment. We are focused on the reduction of air emissions produced from our operations, particularly with respect to flaring of natural gas from our operated well sites. The rapid growth of crude oil production in North Dakota in recent years, coupled with a historical lack of natural gas gathering infrastructure in the state, has led to efforts to reduce flaring of natural gas produced in association with crude oil production. We recognize the environmental and financial risks associated with natural gas flaring, and we seek to manage these risks on an ongoing basis, consistent with applicable requirements.
We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is the inability of operators to promptly connect their wells to natural gas processing and gathering infrastructure due to external factors out of the control of the operator, such as, for example, the granting of right-of-way access by land owners, investment from third parties in the development of gas gathering systems and processing facilities, and the development and adoption of regulations. However, we have allocated significant resources to connect our Bakken and Three Forks wells to natural gas infrastructure to reduce our flared volumes. We have exceeded a goal that we voluntarily set in 2014 to maintain well connections for an average of 90% of our operated Bakken and Three Forks wells, by having approximately 98% of our operated Bakken and Three Forks wells connected to gathering systems since 2015. We believe that achieving this goal helps us to minimize our flared volumes of natural gas.
On July 1, 2014, the NDIC adopted Order No. 24665 (the “July 2014 Order”), pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of 74% of natural gas produced in the state by October 1, 2014, 77% of such gas by January 1, 2015, 85% of such gas by January 1, 2016 and 90% of such gas by October 1, 2020. Modification of the July 2014 Order was announced by the NDIC in the fourth quarter of 2015, resulting in the existing January 1, 2015 gas capture rate of 77% being extended to April 1, 2016 and updated gas capture rates of 80% by April 1, 2016, 85% by November 1, 2016, 88% by November 1, 2018 and 91% by November 1, 2020. The July 2014 Order established an enforcement mechanism for policy recommendations that were previously adopted by the NDIC in March 2014. Those recommendations required all E&P operators applying for new drilling permits in the state after June 1, 2014 to develop Gas Capture Plans that provide measures for reducing the amount of natural gas flared by those operators so as to be consistent with the agency’s gas capture percentage goals. In particular, the July 2014 Order provided that after an initial 90-day period, wells must meet or exceed the NDIC’s gas capture percentage goals on a statewide, county, per-field, or per-well basis. Failure to comply with the gas capture percentage goals will result in an operator having to restrict its production to 200 barrels of oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or 100 barrels of oil per day if less than 60% of such monthly volume of natural gas is captured. As of December 31, 2017, we were capturing approximately 86% of our natural gas production in North Dakota. While we were satisfying the applicable gas capture percentage goals as of December 31, 2017 and expect to satisfy the applicable gas capture percentage goals in the future, there is no assurance that we will remain in compliance in the future or that such future satisfaction of such goals will not have a material adverse effect on our business and results of operations.
Climate change
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

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At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, onshore and offshore oil and natural gas production facilities and onshore processing, transmission, storage and distribution facilities, which include certain of our operations. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rules with the New Source Performance Standards (“NSPS”).
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previously issued NSPS Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards, but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. In another example, the federal Bureau of Land Management (“BLM”) published a final rule in November 2016 that imposes requirements to reduce methane emissions from venting, flaring and leaking on federal and Indian lands. However, in December 2017, the BLM published a final rule that temporarily suspends or delays certain requirements contained in the November 2016 final rule until January 17, 2019. The suspension of the November 2016 final rule is being challenged in court. These rules, should they remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France to prepare an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. While this international agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. However, 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 Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that require reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur increased costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we or our customers produce and lower the value of our reserves as well as reduce demand for our midstream services. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time.
Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, our costs of operations potentially arising from such

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climatic effects, less efficient or non-routine operating practices necessitated by such climate effects, or increased costs for insurance coverage in the aftermath of such effects. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.
Water discharges
The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The EPA and U.S. Army Corps of Engineers (“Corps”) published a final rule in June 2015 that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, including wetlands, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested June 2015 rule would not take effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time, but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
The Oil Pollution Act of 1990 (“OPA”) amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities and onshore facilities, including E&P facilities that may affect waters of the United States. Under the OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.
Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the federal Safe Drinking Water Act (“SDWA”) Underground Injection Control (“UIC”) program and analogous state laws. The UIC program requires permits from the EPA or analogous state agency for disposal wells that we operate, establishes minimum standards for injection well operations and restricts the types and quantities of fluids that may be injected. Any leakage from the subsurface portions of the injection wells may cause degradation of fresh water, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages and personal injuries. Moreover, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be significant. Furthermore, in response to recent seismic events near underground injection wells used for the disposal of produced water from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity. In March 2016, the United States Geological Survey identified Texas as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in Texas, the Texas Railroad Commission adopted rules in 2014 governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These

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developments could result in additional regulation and restrictions on the use of injection wells by us or our customers. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in operational activities, our or our customers’ costs to operate may significantly increase and our ability to continue production or conduct midstream services or dispose of produced water may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.
Hydraulic fracturing activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional formations, including shales. The process involves the injection of water, sand or other proppant and chemical additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.
The hydraulic fracturing process is typically regulated by state oil and natural gas commissions or similar agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in February 2014, the EPA asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. The EPA also issued final CAA regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing or from compressors, controls, dehydrators, storage tanks, natural gas processing plants, and certain other equipment. In addition, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants and, in May 2014, published an ANPR regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court.
From time to time Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states, including North Dakota and Texas where we primarily operate, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Nevertheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from drilling wells.
Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added delays for our operations or increased operating costs in our or our customers’ production of oil and natural gas. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells, which could have a material adverse effect on our business or results of operations with respect to E&P activities and midstream services. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Endangered Species Act considerations
The federal Endangered Species Act (“ESA”) may restrict exploration, development and production activities that may affect endangered and threatened species or their habitats. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States and prohibits the taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitats. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. If endangered or threatened species are located in areas of the underlying properties where we or our customers wish to

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conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of one or more settlements entered into by the U.S. Fish and Wildlife Service (“FWS”), the agency is required to make determinations on the listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us or our customers to incur increased costs arising from species protection measures or could result in delays or limitations on our or our customers’ E&P activities that could have an adverse impact on our ability to develop and produce reserves or an indirect adverse impact on our midstream services.
Operations on federal lands
Performance of oil and natural gas E&P activities on federal lands, including Indian lands and lands administered by the federal BLM are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs, to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. Depending on any mitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could be substantial, and be subject to delays or limitations in the scope of oil and natural gas projects or performance of midstream services. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt our or our customers’ E&P activities. Moreover, depending on the mitigation strategies recommended in the Environmental Assessments or Environmental Impact Statement, we or our customers could incur added costs, which may be significant.
Employee health and safety
We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.
Employees
As of December 31, 2017, we employed 585 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. From time to time we utilize the services of independent contractors to perform various field and other services.
Offices
As of December 31, 2017, we leased 120,543 square feet of office space in Houston, Texas at 1001 Fannin Street, where our principal offices are located. The lease for our Houston office expires in March 2029. We also own field offices in the North Dakota communities of Williston, Powers Lake, Alexander and Watford City.
Available information
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.
Our common stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “OAS.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005.
We also make available on our website at http://www.oasispetroleum.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.

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Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.
Risks related to the oil and natural gas industry and our business
A substantial or extended decline in commodity prices, in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, average daily prices for WTI crude oil ranged from a high of $60.46 per barrel to a low of $42.48 per barrel during 2017. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $3.71 per MMBtu to a low of $2.44 per MMBtu during 2017. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
the actions of OPEC;
the price and quantity of imports of foreign oil and natural gas;
political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America, China, India and Russia;
the level of global oil and natural gas E&P activities;
the level of global oil and natural gas inventories;
localized supply and demand fundamentals and regional, domestic and international transportation availability;
weather conditions and natural disasters;
domestic and foreign governmental regulations;
speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
shareholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas and related infrastructure;
price and availability of competitors’ supplies of oil and natural gas;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
Substantially all of our production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices. Low oil and natural gas prices will reduce our cash flows, borrowing ability, the present value of our reserves and our ability to develop future reserves. See “Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net oil and natural gas reserves” below. Low oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves. See also “The present value of future net revenues from our estimated net proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves” below.
Increased costs of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our

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operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned operating results.
We may not be able to generate enough cash flows to meet our debt obligations.
We expect our earnings and cash flows to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flows may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flows from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flows from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
selling assets;
reducing or delaying capital investments;
seeking to raise additional capital; or
refinancing or restructuring our debt.
If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on our Notes (as defined in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources”). If amounts outstanding under our Revolving Credit Facilities or our Notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources.”
Our Revolving Credit Facilities and the indentures governing our Senior Notes all contain operating and financial restrictions that may restrict our business and financing activities.
Our Revolving Credit Facilities and the indentures governing our Senior Notes (as defined in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources”) contain a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
sell assets, including equity interests in our subsidiaries;
pay distributions on, redeem or repurchase our common stock or redeem or repurchase our debt;
make investments;
incur or guarantee additional indebtedness or issue preferred stock;
create or incur certain liens;
make certain acquisitions and investments;
redeem or prepay other debt;
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
engage in transactions with affiliates;
create unrestricted subsidiaries;
enter into sale and leaseback transactions; and
engage in certain business activities.
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

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Our ability to comply with some of the covenants and restrictions contained in our Revolving Credit Facilities and the indentures governing our Senior Notes may be affected by events beyond our control. If market or other economic conditions deteriorate or if oil and natural gas prices decline substantially or for an extended period of time from their current levels, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Revolving Credit Facilities, the indentures governing our Senior Notes or any future indebtedness could result in an event of default under our Revolving Credit Facilities, the indentures governing our Senior Notes or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.
If an event of default under either of our Revolving Credit Facilities occurs and remains uncured, the lenders under the applicable Revolving Credit Facility:
would not be required to lend any additional amounts to us;
could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;
may have the ability to require us to apply all of our available cash to repay these borrowings; or
may prevent us from making debt service payments under our other agreements.
A payment default or an acceleration under our Revolving Credit Facilities could result in an event of default and an acceleration under the indentures for our Notes. If the indebtedness under the Notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 90% of the reserve value as determined by reserve reports, and if we are unable to repay our indebtedness under the Oasis Credit Facility, the lenders could seek to foreclose on our assets. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources.”
Our level of indebtedness may increase and reduce our financial flexibility.
As of December 31, 2017, we had $70.0 million of outstanding borrowings and had $10.5 million of outstanding letters of credit under the Oasis Credit Facility, $78.0 million of outstanding borrowings under the OMP Credit Facility, $1,191.5 million available for future secured borrowings under our Revolving Credit Facilities and $2,053.0 million outstanding in Notes. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources—Senior secured revolving line of credit,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources—Senior unsecured notes” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources—Senior unsecured convertible notes.” In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.
Our level of indebtedness could affect our operations in several ways, including the following:
a significant portion of our cash flows could be used to service our indebtedness;
a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.
A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. If oil and natural gas prices decline substantially or for an extended period of time from their current levels, we may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital,

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and borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.
In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.
Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:
production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contract obligations; or
there is an increase in the differential between the underlying price in the derivative instrument and actual price received.
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.
Drilling for and producing 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 exploitation, exploration, development and production activities. Our oil and natural gas E&P activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations 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. For a discussion of the uncertainty involved in these processes, see “Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. These levels of uncertainty may be increased with respect to our recently acquired positions in the Delaware Basin due to our inexperience operating in the area. See “The Permian Basin Acquisition represents our initial expansion outside of the Williston Basin, and we may not be successful in operating in other geographic regions” below. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
shortages of or delays in obtaining equipment and qualified personnel;
facility or equipment malfunctions and/or failure;
unexpected operational events, including accidents;
pressure or irregularities in geological formations;
adverse weather conditions, such as blizzards, ice storms and floods;
reductions in oil and natural gas prices;
delays imposed by or resulting from compliance with regulatory requirements;
proximity to and capacity of transportation facilities;
title problems; and
limitations in the market for oil and natural gas.

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Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “Item 1. BusinessOur operations” for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as of December 31, 2017, 2016 and 2015.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.
The present value of future net revenues from our estimated net proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our estimated net proved reserves is the current market value of our estimated net oil and natural gas reserves. In accordance with SEC requirements for the years ended December 31, 2017, 2016 and 2015, we based the estimated discounted future net revenues from our estimated net proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:
actual prices we receive for oil and natural gas;
actual cost of development and production expenditures;
the amount and timing of actual production; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from estimated net proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. Any significant future price changes will have a material effect on the quantity and present value of our estimated net proved reserves.
If oil and natural gas prices decline substantially or for an extended period of time from their current levels, we may be required to take write-downs of the carrying values of our oil and natural gas properties.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. In addition, we assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under our Revolving Credit Facilities. A write-down constitutes a non-cash charge to earnings. A substantial or extended decline in oil and natural gas prices may cause us to incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our Revolving Credit Facilities and our results of operations for the periods in which such charges are taken. Due

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to the volatility of expected future oil prices, we reviewed our proved oil and natural gas properties for impairment as of December 31, 2017, 2016 and 2015. For the year ended December 31, 2017, no impairment was recorded on our proved oil and natural gas properties. For the years ended December 31, 2016 and 2015, we recorded impairment losses of $1.1 million and $9.4 million, respectively, to adjust the carrying values of our proved oil and natural gas properties held for sale to their estimated fair values. During the years ended December 31, 2017, 2016 and 2015, we recorded non-cash impairment charges of $6.9 million, $1.1 million and $36.6 million, respectively, on our unproved properties due to expiring leases and periodic assessments of our unproved properties.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the unavailability of sufficient transportation for our production could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment, supplies and personnel are substantially greater and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms.
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services or the unavailability of sufficient transportation for our production could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital plan, which could have a material adverse effect on our business, financial condition or results of operations. Additionally, compliance with new or emerging legal requirements that affect midstream operations in North Dakota may reduce the availability of transportation for our production. For example, the NDIC adopted regulations in late 2013 that impose more rigorous pipeline development standards on midstream operators, some of whom we rely on to construct and operate pipeline infrastructure to transport the oil and natural gas we produce.
Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations, successfully cleaning out the well bore after completion of the final fracture stimulation stage and successfully protecting nearby producing wells from the impact of fracture stimulation.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as we anticipate. We could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net oil and natural gas reserves.
Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Excluding acquisitions of $54.0 million in 2017 and $781.5 million in 2016, we spent $782.2 million and $400.0 million related to capital expenditures for the years ended December 31, 2017 and 2016, respectively. Our total capital expenditure plan for 2018 is approximately $1,090 million to $1,170 million, which includes approximately $815 million to $855 million for E&P capital expenditures, including approximately $700 million to $730 million focused in the Williston Basin and approximately $115 million to $125 million focused in the Delaware Basin (with approximately 91% of the E&P capital allocated to drilling and completions). Since our initial public offering, our capital expenditures have been financed with proceeds from public equity offerings, proceeds from our issuance of Notes, borrowings under our Revolving Credit Facilities, net cash provided by operating activities, the sale of non-core oil and gas properties and cash settlements of derivative contracts. DeGolyer and MacNaughton projects that we will incur capital costs of $894.6 million over the next five years to develop the proved undeveloped reserves in the Williston Basin covered by its December 31, 2017 reserve report. The actual

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amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
A significant increase in product prices could result in an increase in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flows provided by operating activities, borrowings under our Revolving Credit Facilities and cash settlements of derivative contracts; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional debt or equity securities or the sale of non-strategic assets. The issuance of additional debt or equity may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under the Oasis Credit Facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:
our estimated net proved reserves;
the level of oil and natural gas we are able to produce from existing wells and new projected wells;
the prices at which our oil and natural gas are sold;
the costs of developing and producing our oil and natural gas production;
our ability to acquire, locate and produce new reserves;
the ability and willingness of our banks to lend; and
our ability to access the equity and debt capital markets.
If the borrowing base under our Revolving Credit Facilities or our revenues decrease as a result of low oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our Revolving Credit Facilities is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.
We may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
the timing and amount of capital expenditures;
the operator’s expertise and financial resources;
approval of other participants in drilling wells;
selection of technology; and
the rate of production of reserves, if any.
This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.
All of our producing properties and operations are located in the Williston Basin and Delaware Basin regions, making us vulnerable to risks associated with operating among a limited number of geographic areas.
As of December 31, 2017, 100% of our proved reserves and production were located in the Williston Basin in northwestern North Dakota and northeastern Montana. On February 14, 2018, we closed on the Permian Basin Acquisition, in which we acquired approximately 22,000 net acres in the Delaware Basin. As a result, we may be disproportionately exposed to the impact of economics in the Williston Basin and Delaware Basin or delays or interruptions of production from those wells

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caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in those areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Williston Basin and Delaware Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
The Permian Basin Acquisition represents our initial expansion outside of the Williston Basin, and we may not be successful in operating in other geographic regions.
Our operations have historically focused on a single geographic region, namely the North Dakota and Montana regions of the Williston Basin. Thus, the Permian Basin Acquisition represents our initial entry into the Delaware Basin, and our first expansion of our operations outside of the Williston Basin. Certain aspects related to operating in the Delaware Basin may not be as familiar to us as our existing project areas. As a result, we may encounter obstacles that may cause us not to achieve the expected results of the Permian Basin Acquisition. These obstacles may include a less familiar geological landscape, different completion techniques, midstream and downstream operators with whom we have no established relationship, greater competition for acreage, unfamiliar operating conditions and a distinct regulatory environment. Any adverse conditions, regulations or developments related to our expansion into the Delaware Basin may have a negative impact on our business, financial condition and results of operations.
Our business depends on oil and natural gas gathering and transportation facilities, most of which are owned by third parties.
The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. See also “Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production” and “Insufficient transportation or refining capacity in the Williston Basin and Delaware Basin could cause significant fluctuations in our realized oil and natural gas prices.” We generally do not purchase firm transportation on third party pipeline facilities, and therefore, the transportation of our production can be interrupted by other customers that have firm arrangements. In addition, these third parties may also impose specifications for the products that they are willing to accept. If the total mix of a product fails to meet the applicable product quality specifications, the third parties may refuse to accept all or a part of the products or may invoice us for the costs to handle or damages from receiving the out-of-specification products. In those circumstances, we may be required to delay the delivery of or find alternative markets for that product, or shut-in the producing wells that are causing the products to be out of specification, potentially reducing our revenues.
The disruption of third-party facilities due to maintenance, weather or other interruptions of service could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored. A total shut-in of our production could materially affect us due to a resulting lack of cash flows, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows. Potential crude oil train derailments or crashes could also impact our ability to market and deliver our products and cause significant fluctuations in our realized oil and natural gas prices due to tighter safety regulations imposed on crude-by-rail transportation and interruptions in service.
Insufficient transportation or refining capacity in the Williston Basin and Delaware Basin could cause significant fluctuations in our realized oil and natural gas prices.
The crude oil business environment has historically been characterized by periods when oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for WTI crude oil. In the past, there have been periods when this discount has substantially increased due to the production of oil in the area increasing to a point that it temporarily surpasses the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on oil transportation out of the Williston Basin and Delaware Basin and improved netback pricing received at the lease. On barrels that we transport and sell outside of the basins, our realized price for crude oil is generally the quoted price at the point of sale less transportation costs. In 2016 and 2017, our price differentials relative to WTI strengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail gradually declined. Since the third quarter of 2015, our price differentials have remained less than $5.00 per barrel discount to WTI on a quarterly basis. During 2017, our crude oil price differentials improved to less

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than $2.00 per barrel primarily due to the additional takeaway capacity of the Dakota Access Pipeline of over 450,000 barrels per day.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. 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 to deliver the products to market.
The development of our proved undeveloped reserves in the Williston Basin, Delaware Basin and other areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 36% of our estimated net proved reserves were classified as proved undeveloped as of December 31, 2017. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such as capital markets, our Revolving Credit Facilities and derivative contracts. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our estimated net proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. 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 would be adversely affected.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas E&P activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gas or other pollutants into the environment;
abnormally pressured formations;
shortages of, or delays in, obtaining water for hydraulic fracturing activities;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing failure;
personal injuries and death; and
natural disasters.
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;

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damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Also, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
We have incurred losses in prior years and may do so again in the future.
For the year ended December 31, 2017, we incurred a pre-tax loss of $75.9 million but had positive net income after taxes primarily due to the income tax benefit related to the tax rate change under the Tax Cuts and Jobs Act. For the years ended December 31, 2016 and 2015, we incurred net losses of $243.0 million and $40.2 million, respectively. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures, including planned capital expenditures for 2018 of approximately $1,090 million to $1,170 million.
The uncertainty and risks described in this Annual Report on Form 10-K may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.
Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin and Delaware Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.
Our potential drilling location inventories are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.
Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our execution strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. These levels of uncertainty may be increased with respect to our recently acquired positions in the Delaware Basin due to our inexperience operating in the area. See “The Permian Basin Acquisition represents our initial expansion outside of the Williston Basin, and we may not be successful in operating in other geographic regions” above. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

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Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
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. As of December 31, 2017, we had leases representing 8,163 net acres expiring in 2018, 2,640 net acres expiring in 2019 and 7,244 net acres expiring in 2020. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. During the years ended December 31, 2017, 2016 and 2015, we recorded non-cash impairment charges of $6.9 million, $1.1 million and $36.6 million on our unproved properties due to expiring leases and periodic assessments of our unproved properties.
Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our oil and natural gas E&P operations, oil gathering and transportation activities, natural gas processing services and related operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety aspects, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations and services including the acquisition of a permit before conducting drilling, providing midstream services or other regulated activities; the restriction on types, quantities and concentration of materials that may be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, which may cause us to incur significant capital or operating expenditures or costly actions to achieve and maintain compliance. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting or development or expansion of projects; and the issuance of injunctions limiting or preventing some or all of our operations in affected areas.
Our operations risk incurring significant environmental costs and liabilities as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and waste water discharges related to our operations and due to historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled or processing facilities or pipelines are located and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, accidental spills or other releases could expose us to significant costs and liabilities that could have a material adverse effect on our financial condition or results of operations.
Changes in environmental laws and regulations occur frequently, and any changes that result in delayed, restricted or more stringent or costly well drilling, plant or pipeline construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. For example, in response to a lawsuit filed in the U.S. District Court for the District of Columbia by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court in December 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and natural gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. In another example the EPA and the Corps published a final rule in June 2015 that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, including wetlands, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested June 2015 rule would not take

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effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. Also, in October 2015, the EPA issued a final rule lowering the NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the U.S. not addressed under the November 2017 final rule in the first half of 2018. Additionally, state implementation of these revised NAAQS standards 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. Compliance with any of these rules or any other new or amended legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.
We may not be able to recover some or any of these costs from insurance.
Failure to comply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil and natural gas and may result in substantial penalties.
Our operations are substantially affected by federal, state and local laws and regulations, particularly as they relate to the regulation of oil and natural gas production and transportation. These laws and regulations include regulation of oil and natural gas E&P and related operations, including a variety of activities related to the drilling of wells, the interstate transportation of oil and natural gas by federal agencies such as the FERC, as well as state agencies. We may incur substantial costs in order to maintain compliance with these laws and regulations. As well as recent incidents involving the release of oil and natural gas and fluids as a result of drilling activities in the United States, there have been a variety of regulatory initiatives at the federal and state levels to restrict oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of oil and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on our business, financial condition and results of operations. We must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent we are a shipper on interstate pipelines, we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate capacity.
Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, or the FTC, we could be subject to substantial penalties and fines.
In addition, federal laws prohibit market manipulation in connection with the purchase or sale of oil and/or natural gas. Failure to comply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil and natural gas and may result in substantial penalties. Please see “Item 1. BusinessOther federal laws and regulations affecting our industry.”
Our business involves the selling and shipping by rail of crude oil, including from the Bakken shale and the Delaware Basin, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.
A portion of our crude oil production is transported to market centers by rail. Past derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable materials. Transportation safety regulators in the United States and Canada are concerned that crude oil from the Bakken shale may be more flammable than crude oil from other producing regions and are investigating that issue and are also considering changes to existing regulations to address those possible risks. In May 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank car standard for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, and a requirement that older DOT-111 tank cars be phased out by as early as January 1, 2018 if they are not already retrofitted to comply with new tank car design standards. The rule also includes a new braking standard for certain trains, designates new operational protocols for trains transporting large volumes of flammable liquids, such as routing analyses, speed restrictions and information for local government agencies, and provides new sampling and testing requirements to improve classification of energy products placed into transport. On December 13, 2017, PHMSA announced that it would initiate a rulemaking to rescind the May 2015 rule’s requirements regarding electronically controlled pneumatic brakes.

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In August 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029. Additionally, in July 2016, PHMSA proposed a new rule that would expand the applicability of comprehensive oil spill response plans so that any railroad that transports a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train must have a current, comprehensive, written plan. PHMSA has not yet issued a final version of the rule. In response to a petition from the New York Attorney General, PHMSA issued an ANPR in January 2017 stating that it is considering revising the Hazardous Materials Regulations to establish vapor pressure limits for unrefined petroleum-based products and potentially all Class 3 flammable liquid hazardous materials that would apply during the transportation of the products or materials by any mode. PHMSA has not yet issued a final version of the rule. In addition, in February 2016, the FRA modified its accident and incident reports to gather additional data concerning rail cars carrying crude oil in any train involved in a FRA-reportable accident. In addition to action taken or proposed by federal agencies, a number of states proposed or enacted laws in recent years that encourage safer rail operations or urge the federal government to strengthen requirements for these operations.
Efforts are likewise underway in Canada to assess and address risks from the transport of crude oil by rail. For example, in April 2014, Transport Canada issued a protective order prohibiting oil shippers from using 5,000 of the DOT-111 tank cars and imposing a three year phase out period for approximately 65,000 tank cars that do not meet certain safety requirements. Transport Canada also imposed a 50 mile per hour speed limit on trains carrying hazardous materials and required all crude oil shipments in Canada to have an emergency response plan. At the same time that PHMSA released its 2015 rule, Canada’s Minister of Transport announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule. Likewise, Transport Canada’s rail car retrofitting and phase out timeline largely aligns with the timeline introduced under the 2015 and 2016 PHMSA rules. Transport Canada has also introduced new requirements that railways carry minimum levels of insurance depending on the quantity of crude oil or dangerous goods that they transport as well as a final report recommending additional practices for the transportation of dangerous goods.
These, and future laws, regulatory changes, or initiatives regarding hazardous material transportation, could directly and indirectly increase our operation, compliance and transportation costs and lead to shortages in availability of tank cars. We cannot assure that costs incurred to comply with standards and regulations emerging from these and future rulemakings will not be material to our business, financial condition or results of operations. Moreover, we may incur significant constraints on transportation capacity during the period while tank cars are being retrofitted or newly constructed to comply with the new regulations. In addition, any derailment of crude oil from the Bakken shale involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event.
Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the CAA that establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, certain onshore and offshore oil and natural gas production facilities, and onshore processing, transmission, storage and distribution facilities, which includes certain of our operations. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rules with the NSPS.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published Subpart OOOOa that requires certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previously issued Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control

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practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards, but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. In another example, the BLM published a final rule in November 2016 that imposes requirements to reduce methane emissions from venting, flaring and leaking on federal and Indian lands. However, in December 2017, the BLM published a final rule that temporarily suspends or delays certain requirements contained in the November 2016 final rule until January 17, 2019. The suspension of the November 2016 final rule is being challenged in court. These rules, should they remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France to prepare an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. While this international agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. However, 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 Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur increased costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have an adverse effect on our or our customers’ business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we or our customer produce and lower the value of our reserves as well as reduce demand for our midstream services. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time.
Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, our costs of operations potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by such climate effects, or increased costs for insurance coverage in the aftermath of such effects. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.
Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays that could adversely affect the drilling program’s production of oil and natural gas.
Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the UIC program established under the SDWA. In response to recent seismic events near underground injection wells used for the disposal of produced water from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such injection wells. In March 2016, the United States Geological Survey identified Texas as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in Texas, the Texas Railroad Commission adopted rules in 2014 governing the permitting or re-permitting of wells used to dispose of produced water and other fluids

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resulting from the production of oil and gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or our customers. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in operational activities, our or our customers’ costs to operate may significantly increase and our or our customers’ ability to continue production or conduct midstream services or dispose of produced water may be delayed or limited, which could have a material adverse effect on our business, financial condition and results of operations.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand or other proppant and chemical additives under pressure into the targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.
The process is typically regulated by state oil and natural gas commissions or similar agencies, but several federal agencies have asserted regulatory authority or conducted investigations over certain aspects of the process. For example, in February 2014, the EPA asserted regulatory authority under the SDWA over hydraulic fracturing activities involving the use of diesel; in 2012 and in June 2016 the EPA published final rules governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing or from compressors, controls, dehydrators, storage tanks, natural gas processing plants, and certain other equipment; in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants; and in May 2014, the EPA published an ANPR regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in 2015, the BLM published a final rule establishing new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances.
In addition, from time to time Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including North Dakota and Texas where we primarily operate, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Also, new or more stringent legislation or regulation adopted in areas where we operate could also lead to delays in, or curtailment of, our or our customers’ operations, result in increased operating costs in our or our customers’ production of oil and natural gas, and perhaps cause a decrease in the completion of new oil and natural gas wells, which could have a material adverse effect on our business or results of operations with respect to E&P activities and midstream services. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.

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Operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for E&P activities and the disposal of flowback and produced water may impact operations and have a corresponding adverse effect on our business, financial conditions and results of operations.
Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our E&P operations or midstream services and have a corresponding adverse effect on our business, financial condition and results of operations.
Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our or our customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from E&P activities. Applicable laws, including the Clean Water Act, impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. The EPA and the Corps published a final rule in June 2015 that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, including wetlands, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested June 2015 rule would not take effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time, but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Additionally, regulations implemented under the Clean Water Act and similar state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. In June 2016, the EPA published final regulations prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly-owned wastewater treatment plants. The Clean Water Act and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our or our customers’ flowback and produced water on economic terms may increase our or our customers’ operating costs and cause delays, interruptions or termination of our or our customers’ operations, the extent of which cannot be predicted.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls, substantial changes to existing integrity management programs, or more stringent enforcement of applicable legal requirements could subject us to increased capital and operating costs and operational delays.
Certain of our pipelines are subject to regulation by PHMSA under the HLPSA with respect to oil and condensate and the NGPSA with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of oil and natural gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in HCAs, such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. New laws or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.
The HLPSA and NGPSA were amended by the 2011 Pipeline Safety Act, which among other things, increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety

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issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. In June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.
The adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on our results of operations. For example, in January 2017, PHMSA issued a final rule that significantly extends and expands the reach of certain PHMSA hazardous liquid pipeline integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a HCA. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register remains uncertain following the January 2017 change in Presidential Administrations. In a second example, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as five dwellings within a potential impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their MAOP; and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has not yet finalized the March 2016 proposed rulemaking. New laws or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In the absence of the PHMSA pursuing any legal requirements, state agencies, to the extent authorized, may pursue state standards, including standards for rural gathering lines.
We do not own all of the land on which our pipelines and associated facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and associated facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Additionally, following a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights-of-way or obtain new rights-of-way without experiencing significant costs. Any loss of rights with respect to our real property, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial position and ability to make cash distributions to the unitholders of OMP.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.
Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in

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the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
The loss of senior management or technical personnel could adversely affect our operations.
To a large extent, 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 Thomas B. Nusz, our Chairman and Chief Executive Officer, and Taylor L. Reid, our President and Chief Operating 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.
Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in the Williston Basin and Delaware Basin are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt our ability to operate during such conditions. Results of operations in the Delaware Basin may also be negatively affected by inclement weather during the winter months. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs.
The inability of one or more of our customers or affiliates to meet their obligations to us may adversely affect our financial results.
Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production ($233.7 million in receivables at December 31, 2017), which we market to energy marketing companies, refineries and affiliates, and joint interest receivables ($73.6 million at December 31, 2017).
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the year ended December 31, 2017, sales to Shell Trading (US) Company accounted for approximately 16% of our total sales. For the year ended December 31, 2016, sales to PBF Holding Company LLC accounted for approximately 10% of our total sales. For the year ended December 31, 2015, sales to Shell Trading (US) Company accounted for approximately 10% of our total sales. No other purchasers accounted for more than 10% of our total oil and natural gas sales for the years ended December 31, 2017, 2016 and 2015. We do not require all of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31, 2017, we recorded bad debt expense of $0.6 million as a result of our assessment that it is probable certain receivables may not be collected.
In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. At December 31, 2017, we had derivatives in place with eight counterparties and a total net derivative liability of $135.2 million.
We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting oil and gas prices and future development, production and marketing costs, and the integration of significant acquisitions may be difficult.
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:
recoverable reserves;
future oil and natural gas prices and their appropriate differentials;
development and operating costs;
potential for future drilling and production;
validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and

45


potential environmental and other liabilities, together with associated litigation of such matters.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an “as is” basis. Indemnification from the sellers will generally be effective only during a limited time period after the closing and subject to certain dollar limitations and minimums. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations or cash flows.
Significant acquisitions and other strategic transactions may involve other risks, including:
diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;
difficulty associated with coordinating geographically separate organizations;
an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and
the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. In addition, even if we successfully integrate the assets acquired in an acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame.
If we fail to realize the anticipated benefits of a significant acquisition, such as the Delaware Basin Acquisition, our results of operations may be lower than we expect.
The success of a significant acquisition will depend, in part, on our ability to realize anticipated opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated net proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, in oil and natural gas industry conditions, by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure to retain key personnel, an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stock price may be adversely affected.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.
Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in the title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

46


The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business.
On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has proposed new regulations to set position limits for certain futures, options and swap contracts in designated physical commodities, including, among others, oil and natural gas. The Dodd-Frank Act and CFTC rules have also designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future. To the extent that we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply with the clearing and exchange trading requirements or to take steps to qualify for an exemption to such requirements. In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the non-financial end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the non-financial end-user exception, we could be required to post initial or variation margin, which would impact liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash flows. Other regulations to be promulgated under the Dodd-Frank Act also remain to be finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations.
Recently enacted changes to the U.S. federal income tax laws could adversely affect our financial position, results of operations, and cash flows.
Recently enacted legislation, commonly referred to as the Tax Cuts and Jobs Act, made significant changes to the U.S. federal income taxation of business entities. These changes include a permanent reduction to the corporate income tax rate. Such rate reduction, however, could be offset by other changes intended to broaden the tax base, including (i) imposing new limitations on the utilization of net operating losses, (ii) limiting the deductibility of interest expense, and (iii) eliminating the deduction for certain domestic production activities. The Tax Cuts and Jobs Act is highly complex and subject to interpretation. We continue to examine the impact the Tax Cuts and Jobs Act may have on us, and it could have an adverse effect on our financial position, results of operations, and cash flows. 
We may not be able to utilize a portion of our net operating losses (“NOLs”) to offset future taxable income for U.S. federal or state tax purposes, which could adversely affect our net income and cash flows.
As of December 31, 2017, we had significant federal and state income tax NOLs, which will begin to expire in 2030 and 2018 for U.S. federal and state income tax purposes, respectively. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of an NOL that may be used to offset taxable income when a corporation has undergone an “ownership change.” Determining the limitations under Section 382 is technical and highly complex. We continue to study whether we have undergone or may in the future undergo an ownership change under Section 382. If an ownership has occurred or occurs in the future, we may be prevented from fully utilizing our NOLs, which could adversely affect our net income and cash flows.
An unfavorable resolution of the Mirada Litigation could have a material adverse effect on our business, financial condition, results of operations and cash flows.
On March 23, 2017, Mirada (as defined in Item 3. Legal Proceedings) filed a lawsuit against Oasis Petroleum Inc., OPNA and Oasis Midstream Services LLC in the 334th Judicial District Court of Harris County, Texas. Mirada asserts that it is a

47


working interest owner in certain acreage owned and operated by us and that we have breached certain agreements our predecessors in interest previously entered into with Mirada, or its predecessors interest, with respect to such acreage. We filed an answer denying all of Mirada’s claims, and intend and continue to vigorously defend against Mirada’s claims. Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Although trial is currently scheduled for July 2018, the parties anticipate that the existing trial date will be vacated soon and a new trial date will be selected. On June 30, 2017, Mirada amended its original petition to add a claim that we have has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates. On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively, alleging new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada. Mirada may further amend its petition from time to time to assert additional claims as well as defendants. For further information regarding this lawsuit, please read “Item 3. Legal Proceedings.” We cannot predict the outcome of the Mirada Litigation or the amount of time and expense that will be required to resolve the lawsuit. If such litigation were to be determined adversely to our interests, or if we were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on our business, results of operations and financial condition. Such an adverse determination could materially impact our ability to operate our properties in Wild Basin or develop our identified drilling locations in Wild Basin on our current development schedule. A determination that Mirada has a right to participate in our midstream operations could materially reduce the interests of us in our current assets and future midstream opportunities and related revenues in Wild Basin. In addition, we have agreed to indemnify OMP for any losses resulting from this litigation under the omnibus agreement we entered into with OMP at the time of its initial public offering.
Risks Relating to our Common Stock
We do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, our shareholders’ only opportunity to achieve a return on their investment is if the price of our stock appreciates.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently restricted from making any cash dividends pursuant to the terms of our Revolving Credit Facilities and the indentures governing our Senior Notes. Consequently, our shareholders’ only opportunity to achieve a return on their investment in us will be if the market price of our common stock appreciates, which may not occur, and the shareholder sells their shares at a profit. There is no guarantee that the price of our common stock will ever exceed the price that the shareholder paid.
Our amended and restated certificate of incorporation, as amended, and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our amended and restated certificate of incorporation, as amended, authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation, as amended, and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
a classified Board of Directors, so that only approximately one-third of our directors are elected each year;
limitations on the removal of directors; and
limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of stockholders.
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of Directors.
Conversion of the Senior Convertible Notes may dilute the ownership interest of existing stockholders, or may otherwise depress the market price of our common stock.
The conversion of some or all of the Senior Convertible Notes (as defined in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources”) may dilute the ownership interests of

48


existing stockholders of our common stock. Any sales in the public market of the shares of our common stock issuable upon such conversion could adversely affect prevailing market prices of our common stock. In addition, the existence of the Senior Convertible Notes may encourage short selling by market participants because the conversion of the Senior Convertible Notes could be used to satisfy short positions, and anticipated conversion of the Senior Convertible Notes into shares of our common stock could depress the market price of our common stock.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The information required by Item 2. is contained in Item 1. Business.
Item 3. Legal Proceedings
Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis Petroleum Inc., OPNA and Oasis Midstream Services LLC, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleges new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada.
The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying all of Mirada’s claims and intends and continues to vigorously defend against Mirada’s claims. Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Although trial is currently scheduled for July 2018, the parties anticipate that the existing trial date will be vacated soon and a new trial date will be selected. However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin. In addition, the Company has agreed to indemnify OMP for any losses resulting from this litigation under the omnibus agreement we entered into with OMP at the time of its initial public offering.

49


Item 4. Mine Safety Disclosures
Not applicable.

50


PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for Registrant’s Common Equity. Our common stock is listed on the NYSE under the symbol “OAS.”
The following table sets forth the range of high and low sales prices of our common stock for the two most recent fiscal years as reported by the NYSE:
 
2017
 
2016
 
High
 
Low
 
High
 
Low
1st Quarter
$
16.42

 
$
11.96

 
$
8.78

 
$
3.40

2nd Quarter
$
15.27

 
$
7.36

 
$
11.54

 
$
6.70

3rd Quarter
$
9.41

 
$
6.69

 
$
11.83

 
$
6.56

4th Quarter
$
11.39

 
$
7.57

 
$
17.08

 
$
9.00

Holders. As of February 21, 2018, the number of record holders of our common stock was 636. Based on inquiry, management believes that the number of beneficial owners of our common stock is approximately 40,581.
Dividends. We have not paid any cash dividends since our inception. Covenants contained in our Revolving Credit Facilities and the indentures governing our Senior Notes restrict the payment of cash dividends on our common stock. We currently intend to retain all future earnings for the development of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.
On February 27, 2018, the last sale price of our common stock, as reported on the NYSE, was $8.60 per share.
Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2017.
Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months ended December 31, 2017:
Period
Total
Number  of
Shares
Exchanged(1)
 
Average  Price
Paid
per Share
 
Total Number of  Shares
Purchased as Part of
Publicly Announced
Plans or Programs
 
Maximum Number  (or
Approximate Dollar Value) of
Shares that May Be Purchased
Under the Plans or Programs
October 1 – October 31, 2017
3,259

 
$
9.11

 

 

November 1 – November 30, 2017
1,289

 
10.23

 

 

December 1 – December 31, 2017
393

 
10.46

 

 

Total
4,941

 
$
9.51

 

 

__________________  
(1)
Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.

51


Stock Performance Graph. The following performance graph and related information is “furnished” with the SEC and shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically request that such information be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.
The performance graph shown below compares the cumulative total return to our common stockholders as compared to the cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P 500 O&G E&P”) for the period of December 2012 through December 2017. The comparison was prepared based upon the following assumptions:
1. $100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on December 31, 2012 at the closing price on such date; and
2. Dividends were reinvested.
chart-adc3ffc7909c517b80c.jpg

52


Item 6. Selected Financial Data
Set forth below is our summary historical consolidated financial data for the years ended December 31, 2013 through 2017. This information may not be indicative of our future results of operations, financial position and cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this Annual Report on Form 10-K. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.
 
Year ended December 31,
 
2017
 
2016(1)
 
2015
 
2014
 
2013(1)
 
(In thousands, except per share data)
Statement of operations data:
 
Revenues:
 
 
 
 
 
 
 
 
 
Oil and gas revenues
$
1,034,892

 
$
625,233

 
$
721,672

 
$
1,304,004

 
$
1,084,412

Purchased oil and gas sales
87,989

 
10,272

 

 

 

Midstream revenues
72,752

 
35,406

 
23,769

 
11,614

 
5,742

Well services revenues
52,791

 
33,754

 
44,294

 
74,610

 
51,845

Total revenues
1,248,424

 
704,665

 
789,735

 
1,390,228

 
1,141,999

Expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
177,134

 
135,444

 
144,481

 
169,600

 
94,634

Midstream operating expenses
17,589

 
9,003

 
6,198

 
4,647

 
1,454

Well services operating expenses(2)
37,228

 
20,675

 
24,782

 
45,605

 
29,259

Marketing, transportation and gathering expenses(3)
55,740

 
30,108

 
31,610

 
29,133

 
25,924

Purchased oil and gas expenses
89,320

 
10,258

 

 

 

Production taxes
88,133

 
56,565

 
69,584

 
127,648

 
100,537

Depreciation, depletion and amortization
530,802

 
476,331

 
485,322

 
412,334

 
307,055

Exploration expenses
11,600

 
1,785

 
2,369

 
3,064

 
2,260

Rig termination(4)

 

 
3,895

 

 

Impairment(5)
6,887

 
4,684

 
46,109

 
47,238

 
1,168

General and administrative expenses(2)
91,797

 
89,342

 
89,549

 
92,306

 
75,310

Total operating expenses
1,106,230

 
834,195

 
903,899

 
931,575

 
637,601

Gain (loss) on sale of properties
1,774

 
(1,303
)
 

 
186,999

 

Operating income (loss)
143,968

 
(130,833
)
 
(114,164
)
 
645,652

 
504,398

Other income (expense)
 
 
 
 
 
 
 
 
 
Net gain (loss) on derivative instruments
(71,657
)
 
(105,317
)
 
210,376

 
327,011

 
(35,432
)
Interest expense, net of capitalized interest
(146,837
)
 
(140,305
)
 
(149,648
)
 
(158,390
)
 
(107,165
)
Gain on extinguishment of debt

 
4,741

 

 

 

Other income (expense)
(1,332
)
 
160

 
(2,935
)
 
195

 
1,216

Total other income (expense)
(219,826
)
 
(240,721
)
 
57,793

 
168,816

 
(141,381
)
Income (loss) before income taxes
(75,858
)
 
(371,554
)
 
(56,371
)
 
814,468

 
363,017

Income tax benefit (expense)
203,304

 
128,538

 
16,123

 
(307,591
)
 
(135,058
)
Net income (loss) including non-controlling interests
127,446

 
(243,016
)
 
(40,248
)
 
506,877

 
227,959

Less: Net income attributable to non-controlling interests(6)
3,650

 

 

 

 

Net income (loss) attributable to Oasis
$
123,796

 
$
(243,016
)
 
$
(40,248
)
 
$
506,877

 
$
227,959

Earnings (loss) per share:
 
 
 
 
 
 
 
 

Basic
$
0.53

 
$
(1.32
)
 
$
(0.31
)
 
$
5.09

 
$
2.45

Diluted
0.52

 
(1.32
)
 
(0.31
)
 
5.05

 
2.44

__________________  

53


(1)
Our statement of operations data for the years ended December 31, 2016 and 2013 does not include the full twelve months effects of our acquisitions for 2016 and 2013, respectively. We acquired such interests on December 1, 2016 for our 2016 acquisition, and September 26, 2013 and October 1, 2013 for our 2013 acquisitions. See Note 9 to our audited consolidated financial statements for more information on the 2016 acquisition.
(2)
For the year ended December 31, 2017, certain well services direct field labor compensation expenses are included in well services operating expenses on our Consolidated Statements of Operations, which were previously recognized in general and administrative expenses on our Consolidated Statements of Operations. For the years ended December 31, 2016 and 2015, well services operating expenses have been adjusted to include $2.9 million and $3.7 million, respectively, which were previously recognized in general and administrative expenses on our Consolidated Statements of Operations.
(3)
Prior to the first quarter of 2017, marketing, transportation and gathering expenses included purchased oil and gas expenses, which represent the crude oil purchased primarily for blending at our crude oil terminal. Prior periods have been adjusted retrospectively to reflect these expenses in purchased oil and gas expenses on our Consolidated Statements of Operations. For the year ended December 31, 2016, marketing, transportation and gathering expenses have been adjusted to exclude $10.3 million of purchased oil and gas expenses.
(4)
During the year ended December 31, 2015, we elected to early terminate certain drilling rig contracts and recorded rig termination expenses of $3.9 million.
(5)
For the years ended December 31, 2016, 2015 and 2014, impairment includes $1.1 million, $9.4 million and $40.0 million, respectively, related to our proved properties. See Note 8 to our audited consolidated financial statements.
(6)
As OMP completed its initial public offering on September 25, 2017, the net income attributable to non-controlling interests represents the OMP interest owned by the public for the period from September 25, 2017 through December 31, 2017.
 
At December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In thousands)
Balance sheet data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
16,720

 
$
11,226

 
$
9,730

 
$
45,811

 
$
91,901

Net property, plant and equipment
6,173,486

 
5,919,567

 
5,218,242

 
5,186,786

 
4,079,750

Total assets(1)
6,615,130

 
6,178,632

 
5,649,375

 
5,909,076

 
4,678,041

Long-term debt(1)
2,097,606

 
2,297,214

 
2,302,584

 
2,670,664

 
2,501,687

Total stockholders’ equity
3,513,579

 
2,923,157

 
2,319,342

 
1,872,301

 
1,348,549

 __________________  
(1)
Prior to 2015, we presented deferred financing costs related to our Senior Notes in other assets on our Consolidated Balance Sheets. Upon the adoption of new accounting guidance in 2015, such costs are presented as a deduction from the carrying value of long-term debt. As of December 31, 2017, 2016 and 2015, deferred financing costs related to our Notes totaling $23.0 million, $28.3 million and $35.4 million, respectively, were included in long-term debt on our Consolidated Balance Sheets. Prior periods have been adjusted retrospectively to reflect the period-specific effects of applying the new guidance. Reclassified amounts total $29.3 million and $33.9 million for the years ended December 31, 2014 and 2013, respectively.
 
Year ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In thousands)
Other financial data:
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
507,876

 
$
228,018

 
$
359,815

 
$
872,516

 
$
697,856

Net cash used in investing activities
(714,760
)
 
(1,070,828
)
 
(479,148
)
 
(1,077,452
)
 
(2,445,076
)
Net cash provided by financing activities
212,378

 
844,306

 
83,252

 
158,846

 
1,625,674


54


Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary note regarding forward-looking statements.”
Overview
We are an independent E&P company focused on the acquisition and development of onshore, unconventional oil and natural gas resources in the United States. Since our inception, we have acquired properties that provide current production and significant upside potential through further development. During 2017, our drilling activity was focused in the North Dakota and Montana regions of the Williston Basin and was primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken and Three Forks formations. OPNA conducts our domestic oil and natural gas E&P activities in the Williston Basin. On February 14, 2018, we closed on the Permian Basin Acquisition, representing our initial entry into the Delaware Basin. In 2018, we will continue our drilling and completion activities in the Williston Basin and will also begin operations in the Delaware Basin.
We also operate a midstream services business through OMS, through which the Company owns a majority of the outstanding units of OMP following OMP’s initial public offering, which was completed on September 25, 2017, and a well services business through OWS, both of which are separate reportable business segments that are complementary to our primary development and production activities. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. We built our Williston Basin assets through acquisitions and development activities, which were financed with a combination of capital from private investors, borrowings under (i) the Oasis Credit Facility and (ii) the OMP Credit Facility, cash flows provided by operating activities, proceeds from our Notes, proceeds from our public equity offerings, the sale of certain non-core oil and gas properties and cash settlements of derivative contracts. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided an entry into a new area of interest or complemented our existing operations. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
Due to the geographic concentration of our oil and natural gas properties in the Williston Basin and Delaware Basin, we believe the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:
commodity prices for oil and natural gas;
transportation capacity;
availability and cost of services; and
availability of qualified personnel.
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations and may fluctuate widely in the future. As a result of current oil prices, we have increased our planned 2018 capital expenditures as compared to 2017, excluding acquisitions, and we are continuing to concentrate our drilling activities in certain areas that are the most economic in the Williston Basin as well as on our recently acquired Delaware Basin acreage. A substantial or extended decline in prices for oil or natural gas could materially

55


and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. We enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. Currently, we are flowing approximately 90% of our gross operated oil production through these gathering systems. Please see “Item 1. BusinessMarketing, transportation and major customers.”
Our quarterly average net realized oil prices and average price differentials are shown in the tables below.
 
2017
 
Year ended
December 31, 2017
 
Q1
 
Q2
 
Q3
 
Q4
 
Average Realized Oil Prices ($/Bbl)(1)
$
47.03

 
$
44.61

 
$
46.35

 
$
54.97

 
$
48.52

Average Price Differential ($/Bbl)(2)
$
4.88

 
$
3.68

 
$
1.82

 
$
0.50

 
$
2.60

Average Price Differential Percentage(2)
9
%
 
8
%
 
4
%
 
1
%
 
5
%
 
2016
 
Year ended
December 31, 2016
 
Q1
 
Q2
 
Q3
 
Q4
 
Average Realized Oil Prices ($/Bbl)(1)
$
28.74

 
$
40.81

 
$
40.54

 
$
44.57

 
$
38.64

Average Price Differential ($/Bbl)(2)
$
4.85

 
$
4.86

 
$
4.40

 
$
4.91

 
$
4.76

Average Price Differential Percentage(2)
14
%
 
11
%
 
10
%
 
10
%
 
11
%
 
2015
 
Year ended
December 31, 2015