---

---

•	our business strategic tactics;

•	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 and Delaware Basins 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 hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•	potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities;

•	changes in environmental, safety and other laws and regulations;

•	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;

•	the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;

•	uncertainty regarding future operating results;

•	plans, objectives, expectations and intentions contained in this report that are not historical;

•	our ability to remediate the identified material weakness in our internal control over financial reporting; and

•	certain factors discussed elsewhere in this Form 10-K.

---

•

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 2018, we completed and brought on production 114 gross (79.0 net) operated wells in the Williston Basin and 7 gross (6.3 net) operated wells in the Delaware Basin. As of December 31, 2018, we had 64 gross operated wells waiting on completion in the Williston Basin and 4 gross operated wells awaiting completion in the Delaware Basin. Our 2019 capital plan contemplates completing and placing on production approximately 70 gross operated wells in the Williston Basin and approximately 9 to 11 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 2019 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 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, 2018, we had $972.2 million of liquidity available, including $22.2 million of cash and cash equivalents and $950.0 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 Operations—Liquidity 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.

•

Substantial leasehold position in two 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, 2018, we had 413,552 net leasehold acres in the Williston Basin, of which 400,711 net acres were held by production, and 70% of our 280.1 MMBoe estimated net proved reserves in this area were comprised of oil. In addition, we made our initial entry into one of the most prolific oil plays in North America, the Delaware Basin. As of December 31, 2018, we had 23,366 net leasehold acres in the Delaware Basin, of which 15,767 net acres were held by production, and 80% of our 40.5 MMBoe estimated net proved reserves in this area were comprised of oil. In 2019, we will continue our drilling and completion activities in the Williston Basin as well as 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 top-tier inventory. We plan to complete approximately 70 gross operated wells with a working interest of approximately 65% in the Williston Basin and approximately 9 to 11 gross operated wells with a working interest of approximately 90% in the Delaware Basin in 2019.

•

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 2018, an average of 70% of our executive officers’ overall compensation was in long-term equity-based incentive awards, and such officers owned approximately 4.0 million shares of our outstanding common stock as of December 31, 2018. 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, 2018, 96% of our estimated net proved reserves were attributable to properties that we expect to operate. Approximately 94% of our 2018 drilling and completion capital expenditures and approximately 97% of our 2019 plan are related to operated wells. Controlling operations will allow us to dictate the pace of development and better manage the costs, type

---

•

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.

---

(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.

---

---

---

•	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.

(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)

Cash E&P G&A, a non-GAAP measure, represents general and administrative expenses less non-cash equity-based compensation expenses included in our exploration and production segment. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for a reconciliation of our exploration and production segment general and administrative expenses to Cash E&P G&A.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

•	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 and policies, including environmental requirements;

•	speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

•	stockholder 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.

---

•	selling assets;

•	reducing or delaying capital investments;

•	seeking to raise additional capital; or

•	refinancing or restructuring our debt.

•	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.

•	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 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.

---

•	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.

•	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.

•	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.

---

---

•	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.

---

•	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.

---

---

•	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.

•	injury or loss of life;

•	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.

---

---

---

---

---

---

---

---

---

•	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

•	potential environmental and other liabilities, together with associated litigation of such matters.

•	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.

---

---

---

•	supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;

•	delays in delivering or failure to deliver product at the tailgate of our facilities, resulting in a loss of revenues;

•	operational disruption resulting in loss of revenues;

•	events of non-compliance that could lead to regulatory fines or penalties; and

•	business interruptions that could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.

---

•	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.

---

---

---

(1)	Represent shares that employees surrendered back to us that equaled in value the amount needed to pay 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.

---

1.	$100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on December 31, 2013 at the closing price on such date; and

2.	Dividends were reinvested.

---

---

(1)	Our statement of operations data for the years ended December 31, 2018 and 2016 do not include the full twelve months effects of our acquisitions for 2018 and 2016, respectively. We acquired such interests on February 14, 2018 for our 2018 acquisition and December 1, 2016 for our 2016 acquisition. See Note 10 to our consolidated financial statements for more information on the 2018 acquisition.

(2)

We have revised the Consolidated Statements of Operations to correct the presentation of certain purchase and sale arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in oil and gas revenues, by increasing purchased oil and gas sales and purchased oil and gas expenses by $45.6 million and $45.3 million, respectively, and decreasing oil and gas revenues by $0.3 million for the year ended December 31, 2017. See Note 2 to our consolidated financial statements for more information on this revision.

(3)	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, for certain well services direct field labor compensation expenses which were previously recognized in general and administrative expenses on our Consolidated Statements of Operations.

(4)

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.

(5)	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.

(6)

As OMP completed its initial public offering on September 25, 2017, 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. As of November 19, 2018, net income attributable to non-controlling interests represents the OMP interest owned by the public following the OMP Dropdown. See Note 3 to our consolidated financial statements for more information on the OMP Dropdown.

(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, 2018, 2017, 2016 and 2015, deferred financing costs related to our Senior Notes totaling $20.9 million, $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 for the year ended December 31, 2014.

(2)

We have revised the Consolidated Balance Sheets to correct the presentation of certain purchase and sale arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in accounts receivable, by increasing both accounts receivable and accrued liabilities by $7.8 million as of December 31, 2017, which resulted in increases in both total assets and total liabilities. See Note 2 to our consolidated financial statements for more information on this revision.

---

•	commodity prices for oil and natural gas;

•	transportation capacity;

•	availability and cost of services; and

•	availability of qualified personnel.

---

(1)	Realized oil prices do not include the effect of derivative contract settlements.

(2)	Price differential reflects the difference between realized oil prices and WTI crude oil index prices.

---

•	We increased our production guidance twice in 2018, which was adjusted for divestitures. Our production volumes averaged 88,288 barrels of oil equivalent per day (“Boepd”) (76.2% oil) in the fourth quarter of 2018, in-line with midpoint guidance. Our production volumes averaged 82,525 Boepd (76.5% oil) for the year ended December 31, 2018;

•	We lowered our lease operating expenses (“LOE”) per barrels of oil equivalent (“Boe”) by over 12% year over year to $6.44 per Boe for the year ended December 31, 2018;

---

•	We completed and placed on production 121 gross (85.3 net) operated wells, including 114 gross (79.0 net) operated wells in the Williston Basin and 7 gross (6.3 net) operated wells in the Delaware Basin, while investing $942.2 million of exploration and production capital expenditures, which excludes acquisitions, other capital and midstream capital, during 2018;

•	We closed and integrated the Permian Basin Acquisition of approximately 22,000 net core acres in the over-pressured oil window of the Delaware Basin. Additionally, we purchased adjacent acreage at attractive pricing, bringing our total position to over 23,000 net acres in the Delaware Basin;

•	OMP completed the construction and startup of a second natural gas plant in Wild Basin, making us the second largest natural gas processor in North Dakota;

•	We successfully executed a divestiture “dropdown” of additional interests in midstream subsidiaries to OMP for $251.4 million, which increased our holdings of OMP common units and reduced debt;

•	We high-graded our portfolio since announcing the Permian Basin Acquisition, including non-strategic divestitures of $340.0 million, which helped reduce financial leverage during the year ended December 31, 2018; and

•

Net cash provided by operating activities was $996.4 million for the year ended December 31, 2018. Adjusted EBITDA, a non-GAAP financial measure, was $958.7 million for the year ended December 31, 2018. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) including non-controlling interests and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.

---

(1)

We have revised the Consolidated Statements of Operations to correct the presentation of certain purchase and sale arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in oil and gas revenues, by increasing purchased oil and gas sales and purchased oil and gas expenses by $45.6 million and $45.3 million, respectively, and decreasing oil and gas revenues by $0.3 million for the year ended December 31, 2017. See Note 2 to our consolidated financial statements for more information on this revision.

(2)

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.

(3)	Natural gas prices include the value for natural gas and natural gas liquids.

---

---

(1)

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 year ended December 31, 2016, well services operating expenses has been adjusted to include $2.9 million, which was previously recognized in general and administrative expenses on our Consolidated Statements of Operations.

(2)

Prior to the first quarter of 2017, marketing, transportation and gathering expenses included purchased oil and gas expenses related to blending at our crude oil terminal on our Consolidated Statements of Operations. 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 has been adjusted to exclude $10.3 million of purchased oil and gas expenses.

(3)	We have revised the Consolidated Statements of Operations to correct the presentation of certain purchase and sale arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in oil and gas revenues, by increasing purchased oil and gas sales and purchased oil and gas expenses by $45.6 million and

---

(4)

As OMP completed its initial public offering on September 25, 2017, 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. As of November 19, 2018, net income attributable to non-controlling interests represents the OMP interest owned by the public following the OMP Dropdown. See Note 3 to our consolidated financial statements for more information on the OMP Dropdown.

---

---

---

---

---

(1)	Other capital expenditures include such items as administrative capital and capitalized interest.

(2)	Midstream capital expenditures attributable to OMP was $116.6 million for the year ended December 31, 2018.

(3)

Total capital expenditures (including acquisitions) reflected in the table above differs from the amounts for capital expenditures and acquisitions shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis. In addition, for the year ended December 31, 2018, total capital expenditures (including acquisitions) reflected in the table includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition. See Note 10 to our consolidated financial statements for more information on the Permian Basin Acquisition.

---

(1)	E&P and other capital expenditures include OWS and administrative capital and excludes capitalized interest of approximately $15 million.

(2)	Midstream capital expenditures include approximately $19 million to $21 million for midstream capital expenditures attributable to Oasis.

---

•	a prohibition against incurring debt, subject to permitted exceptions;

•	a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;

•	a prohibition against making investments, loans and advances, subject to permitted exceptions;

•	restrictions on creating liens and leases on our assets and our subsidiaries, subject to permitted exceptions;

•	restrictions on merging and selling assets outside the ordinary course of business;

•	restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;

•	a provision limiting oil and natural gas derivative financial instruments;

•	a requirement that we maintain a ratio of consolidated EBITDAX (as defined in the Oasis Credit Facility) to consolidated Interest Expense (as defined in the Oasis Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter;

•

a requirement that we maintain a Current Ratio (as defined in the Oasis Credit Facility) of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the Oasis Credit Facility) to consolidated current liabilities (with exclusions as described in the Oasis Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter; and

•

if the Aggregate Elected Commitment Amounts (as defined in the Oasis Credit Facility) exceed 85% of the effective borrowing base (“Trigger”), we are required to maintain a ratio of total debt (as defined in the Oasis Credit Facility) to consolidated EBITDAX (as defined in the Oasis Credit Facility) (the “Leverage Ratio”). The Leverage Ratio will be first tested during the quarter in which the Trigger occurs. The Leverage Ratio shall continue to be tested as long as the Aggregate Elected Commitment Amounts exceed 85% of the effective borrowing base, and shall not exceed 4.25 to 1.00 for the first two quarters and 4.00 to 1.00 for each fiscal quarter thereafter.

---

---

---

(1)	See Note 12 to our consolidated financial statements for a description of our senior unsecured notes, Revolving Credit Facilities and related interest payments. As of December 31, 2018, we had $468.0 million of borrowings and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility and $318.0 million of borrowings under the OMP Credit Facility.

(2)

Amounts represent the present value of estimated costs expected to be incurred in the future to plug, abandon and remediate our oil and gas properties and produced and flowback water disposal wells at the end of their productive lives. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 13 to our consolidated financial statements.

(3)	See Note 20 to our consolidated financial statements for a description of our operating leases and volume commitment agreements.

---

---

•	the remaining amount of unexpired term under our leases;

•	our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;

•	our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

•	our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

•	our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston Basin and the Bone Spring and Wolfcamp formations in the Delaware Basin by us or by other operators in areas adjacent to or near our unproved properties.

---

---

---

---

---

(1)	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)

Capital expenditures (including acquisitions) reflected in the table above differ from the amounts shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis. Acquisitions totaled $951.9 million, $54.0 million and $781.5 million for the years ended December 31, 2018, 2017 and 2016, respectively. In addition, capital expenditures

---

(1)	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.

---

---

(1)	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)	The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-recurring items. The tax impact was not computed for the tax reform rate change adjustments.

(3)

We included 3,379,000 and 2,889,000 of unvested stock awards for the years ended December 31, 2018 and 2017, respectively, in computing Adjusted Diluted Income Attributable to Oasis Per Share due to the dilutive effect under the treasury stock method. No unvested stock awards were included in computing Adjusted Diluted Loss Attributable to Oasis Per Share for the year ended December 31, 2016 because the effect was anti-dilutive due to Adjusted Net Loss Attributable to Oasis.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

•	the remaining amount of unexpired term under its leases;

•	its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;

•	its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

•	its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

•	its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston Basin and Bone Springs and Wolfcamp formations in the Delaware Basin by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.

---

---

---

---

---

---

---

---

---

---

•

Crude oil and natural gas revenues. The Company is party to certain contracts for crude oil gathering, stabilization, blending, storage and transportation, as well as gas gathering, compression, processing and gas lift services. Under these customer contracts, the Company provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient.

•

Water revenues. The Company is party to certain contracts with customers for produced and flowback water gathering and disposal services, under which it provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient.

---

•

Purchased oil sales. The Company purchases and sells crude oil at various delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be sold and delivered to the customer at a specified delivery point. The Company purchases and sells the crude oil to different counterparties at market-based prices. Market-based pricing is based on the price index applicable for the location of the sale.

•

Purchased gas sales. The Company is party to certain purchase arrangements with third parties pursuant to which the Company purchases natural gas from third parties at a connection point and obtains control prior to performing services and is the principal in the transaction. The Company gathers, compresses and/or processes the gas and then redelivers the residue gas and NGLs to different counterparties at market-based prices.

•

Water revenues. Under its customer contracts for freshwater supply and distribution, the Company supplies and distributes freshwater to its customers for hydraulic fracturing and production optimization. These contracts contain multiple distinct performance obligations since each freshwater barrel can be sold separately and is not dependent nor highly interrelated with other barrels. Revenue associated with freshwater supply and distribution services is recognized at a point-in-time based upon the transaction price when title, control and risk of loss transfers to the customer, which occurs at the delivery point.

(1)	Represents midstream revenues excluding all intercompany revenues for work performed by the midstream services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in midstream services revenues.

---

(1)	Represents well services revenues excluding all intercompany revenues for work performed by the well services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in well services revenues.

---

---

---

---

---

---

(1)	Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $40.5 million and $38.4 million at December 31, 2018 and 2017, respectively.

(2)	Included in the Company’s other property and equipment are estimates of future asset retirement costs of $1.3 million and $1.5 million at December 31, 2018 and 2017, respectively.

---

---

---

---

---

•	a prohibition against incurring debt, subject to permitted exceptions;

•	a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;

•	a prohibition against making investments, loans and advances, subject to permitted exceptions;

•	restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;

•	restrictions on merging and selling assets outside the ordinary course of business;

•	restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;

•	a provision limiting oil and natural gas derivative financial instruments;

•	a requirement that the Company maintain a ratio of consolidated EBITDAX (as defined in the Oasis Credit Facility) to consolidated Interest Expense (as defined in the Oasis Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter;

•

a requirement that the Company maintain a Current Ratio (as defined in the Oasis Credit Facility) of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the Oasis Credit Facility) to consolidated current liabilities (with exclusions as described in the Oasis Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter; and

---

•

if the Aggregate Elected Commitment Amounts (as defined in the Oasis Credit Facility) exceed 85% of the effective borrowing base (“Trigger”), the Company is required to maintain a ratio of total debt (as defined in the Oasis Credit Facility) to consolidated EBITDAX (as defined in the Oasis Credit Facility) (the “Leverage Ratio”). The Leverage Ratio will be first tested during the quarter in which the Trigger occurs. The Leverage Ratio shall continue to be tested as long as the Aggregate Elected Commitment Amounts exceed 85% of the effective borrowing base, and shall not exceed 4.25 to 1.00 for the first two quarters and 4.00 to 1.00 for each fiscal quarter thereafter.

---

---

(1)	Includes costs for wells acquired in the Permian Basin Acquisition (see Note 10 – Acquisitions) as of December 31, 2018.

(2)	Liabilities settled during the years ended December 31, 2018 and 2017 included ARO related to sold properties (see Note 11 – Divestitures).

(3)	Included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations.

---

---

---

---

---

---

(1)	No unvested stock awards were included in computing loss per share for the years ended December 31, 2018 and 2016 because the effect was anti-dilutive.

---

---

(1)	Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

(2)

Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions of oil and gas properties shown in the Company’s Consolidated Statements of Cash Flows because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the Consolidated Statements of Cash Flows are presented on a cash basis. Acquisitions totaled $951.9 million, $54.0 million and $781.5 million for the years ended December 31, 2018, 2017 and 2016, respectively, in the exploration and production segment. Additionally, capital expenditures (including acquisitions) reflected in the table includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition for the year ended December 31, 2018.

---

---

---

---

---

---

---

---

---

---

---

---

---

(1)	Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $40.5 million and $38.4 million at December 31, 2018 and 2017, respectively.

---

---

(1)	Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.

---

---

---

(1)	For the quarters during the years ended December 31, 2018 and 2017, the impacts of the revision to the Company's Consolidated Statements of Operations are presented in the following tables:

---

---

---

•	Enhancement of the controls over all purchase and sale arrangements;

•	Revision and communication of the accounting controls, policies and procedures relating to the application of ASC 845; and

•	Enhancement of integration and documentation of standards within and between accounting, marketing and other key departments to timely identify transactions that are subject to ASC 845.

---

---

(1)	Financial Statements:

(2)	Financial Statement Schedules:

(3)	Exhibits:

---

---

---

---

(a)	Filed herewith.

(b)	Furnished herewith.

---

---

---

---