Item 1. Business
Item 1. Business
Overview
Oasis Petroleum Inc. (together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”), a Delaware corporation, is an independent exploration and production (“E&P”) company formed in 2007 focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct our E&P activities and own our oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Permian Basin, respectively. In addition to our E&P segment, we also operate a midstream business segment primarily through Oasis Midstream Partners LP (“OMP”). OMP is a premier gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets in North America. We own a substantial majority of the general partner and a majority of the outstanding units of OMP. We derive significant cash flows from the midstream segment through distributions from our ownership of OMP limited partner units, distributions from the general partner and our retained ownership of equity interests in certain OMP subsidiaries.
As of December 31, 2020, we have 401,766 net leasehold acres in the Williston Basin, of which approximately 98% is held by production, and 24,396 net leasehold acres in the Permian Basin, of which approximately 74% is held by production. In the Williston Basin, we are currently exploiting significant resource potential from the Middle Bakken and Three Forks formations, which are present across a substantial portion of our acreage. In the Permian Basin, our development activities are focused on the Bone Spring and Wolfcamp formations, and our advanced geologic position supports strong inventory across multiple pay zones. We believe the locations, size and concentration of our acreage in the Williston and Permian Basins create an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs and has substantial Williston Basin and Permian Basin experience.
As of December 31, 2020, we had 1,127 gross (827.9 net) operated producing horizontal wells in the Williston Basin and 57 gross (53.4 net) operated producing horizontal wells in the Permian Basin, and our total average daily production in 2020 was 64,717 barrels of oil equivalent per day (“Boepd”). As of December 31, 2020, DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 152.2 million barrels of oil equivalent (“MMBoe”) in the Williston Basin, of which 74% were classified as proved developed and 63% were crude oil, and net proved reserves to be 30.3 MMBoe in the Permian Basin, of which 55% were classified as proved developed and 80% were crude oil.
Voluntary Reorganization under Chapter 11 and Emergence from Bankruptcy
On September 30, 2020 (the “Petition Date”), Oasis Petroleum Inc. and certain of our direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On November 10, 2020, the Bankruptcy Court confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the “Plan”), and the Debtors emerged from bankruptcy on November 19, 2020 (the “Emergence Date”). OMP and its subsidiaries were not included in the Chapter 11 Cases.
As a result of the restructuring, we strengthened our balance sheet, reducing our total indebtedness by $1.8 billion by issuing equity in a reorganized entity to the holders of our senior unsecured notes. For more information on our emergence from the Chapter 11 Cases and related matters, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” and “Part II, Item 8. Financial Statements and Supplementary Data—Note 2—Emergence from Voluntary Reorganization under Chapter 11.”
Fresh start accounting
Upon emergence from bankruptcy, we adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes. Accordingly, the consolidated financial statements on or after November 19, 2020 are not comparable to the consolidated financial statements prior to that date. References to “Successor” relate to our financial position and results of operations as of and subsequent to the Emergence Date. References to “Predecessor” relate to our financial position prior to, and our results of operations through and including, the Emergence Date. For more information related to fresh start accounting, see “Part II. Item 8. Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting.”
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Business Strategy
Our new operational and financial strategy is focused on rigorous capital discipline and generating free cash flow by executing on the following strategic priorities:
• Returns-focused business model. We intend to generate significant free cash flow and sustainable full cycle returns by efficiently developing our acreage positions in the Williston and Permian Basins while maintaining rigorous capital discipline. Our Board of Directors established a capital allocation committee that developed a framework focused on systematic evaluation and screening of capital investments to ensure strong returns, which forms the foundation of the Company’s budgeting process. We intend to reinvest capital well within cash flow and return capital to shareholders. We declared a dividend of $0.375 per share of common stock payable on March 22, 2021 to shareholders of record as of March 8, 2021. Additionally, our management team is focused on maintaining our strong balance sheet and financial flexibility. As of December 31, 2020, we had $449.0 million of liquidity available, including $15.9 million of cash and cash equivalents and $433.2 million in the aggregate of unused borrowing capacity available under the Oasis Credit Facility and the OMP Credit Facility (both as defined in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments”). Our liquidity position, along with expected cash flows from operations, will provide continued financial flexibility as we actively manage the pace of development on our acreage positions.
• Operational excellence. Our management team is focused on continuous improvement of our operations and overall cost structure and has significant experience in successfully operating cost-efficient development programs. We have initiated an extensive third-party review of our cost structure and organizational efficiency and are targeting new material cost and capital efficiencies. The magnitude and concentration of our acreage within the Williston and Permian Basins, particularly in the core of the plays, allows us to capture economies of scale, including the ability to drill multiple wells from a single drilling pad into multiple formations, utilize centralized production and crude oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization.
Our team is focused on employing leading drilling and completion techniques to optimize overall project economics. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. We continue to optimize our completion designs based on geology and well spacing.
• Environmental, social and governance leadership. We are committed to environmental, social and governance (“ESG”) initiatives and continue to implement new ESG best practices. We work to provide safe, reliable energy in a responsible manner while meeting the expectations of a carbon-constrained world. We are focused on identifying opportunities to minimize our environmental impact, improve safety, invest in our employees and support the communities in which we live and work.
We are a recognized industry leader in the capture of the natural gas that we produce due to the proactive and significant investments we have made in our midstream business. As of December 31, 2020, we were capturing approximately 96% of our natural gas production in North Dakota, and our flared gas percentage is two-thirds less than the average for North Dakota operators. In addition, we capture gas for other operators, reducing industry-wide emissions.
We provide leadership training and educational and professional development programs for employees at every level of the organization. We have also made meaningful investments in safety training programs that benefit our employees as well as employees of other operators and contractors. We are deeply involved in the areas in which we work and deploy our financial resources, time and talent to support a number of charitable organizations and our local communities.
Our refreshed Board of Directors is comprised of experienced energy industry professionals and 83% independent. The Board of Directors established the Nominating, Environmental, Social and Governance Committee to oversee our ESG policies. We have implemented compensation practices focused on value creation and aligned with shareholder interests. For more information about our ESG and corporate responsibility efforts, please see the “Sustainability” page of our website and the Proxy Statement that we will file for our 2021 Annual Meeting of Shareholders.
• Portfolio review. We are reviewing our E&P portfolio of quality assets in the Williston and Permian Basins for fit with our new business model focused on generating free cash flow and sustainable returns. In addition, we are evaluating our midstream position for optimal structure and value creation options.
• Consolidation. We will evaluate and pursue strategic acquisition opportunities that enhance shareholder value and build scale. As opportunities arise, we intend to identify and acquire additional acreage and producing assets to
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supplement our existing operations. We may acquire additional acreage in the Williston Basin and the Permian Basin or may selectively target additional basins that would allow us to execute large, repeatable development drilling programs.
Competitive Strengths
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
• Best-in-class balance sheet. We believe our strong balance sheet will allow us to generate significant free cash flow and corporate-level returns. We have no near-term debt maturities. We are focused on rigorous capital discipline and have a robust hedging program to minimize downside risk.
• Incentivized 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. 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 large, repeatable development drilling programs. In addition, a substantial majority of our executive officers’ overall compensation has been in long-term equity-based incentive awards, and we have implemented best-in-class management compensation practices aligned with shareholders, which we believe provides them with significant incentives to grow the value of our business and return capital to shareholders.
• Substantial leasehold position in two of North America’s leading unconventional crude 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 and will continue to provide significant free cash flow generation. As of December 31, 2020, we had 401,766 net leasehold acres in the Williston Basin, of which 393,719 net acres were held by production, and 63% of our 152.2 MMBoe estimated net proved reserves in this area were comprised of crude oil. We believe our Permian Basin leasehold position provides attractive rates of return in the deepest part of one of the most prolific crude oil plays in North America across the highly contiguous blocks of acreage. As of December 31, 2020, we had 24,396 net leasehold acres in the Permian Basin, of which 17,933 net acres were held by production, and 80% of our 30.3 MMBoe estimated net proved reserves in this area were comprised of crude oil. We believe we have a large project inventory of potential drilling locations that we have not yet drilled, a majority of which are operated by us. In 2021, we will continue our drilling and completion activities in both the Williston and Permian Basins.
• 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, 2020, 97% of our estimated net proved reserves were attributable to properties that we expect to operate. In 2021, we plan to complete approximately 23 to 25 gross operated wells with an average working interest of approximately 86% in the Williston Basin and approximately 6 to 8 gross operated wells with an average working interest of approximately 100% in the Permian Basin. In addition to our E&P position, we have a robust midstream infrastructure platform that we control that provides attractive cost and certainty of service. Controlling operations enables us to optimize capital allocation and control the pace of development of our assets to manage our reinvestment rates in line with our broader strategic objectives. Additionally, operational control allows us to materially benefit from proactively managing our cost structure across our portfolio, including both our E&P and midstream segments. We believe that maintaining operational control over the majority of our acreage allows us to better pursue our strategies of enhancing returns through operational and cost efficiencies and capital efficiency. We are also better able to manage infrastructure investment to drive down operating costs and optimize crude oil, natural gas and NGL price realizations.
• Vertical integration. Our investment in and operational control of our midstream business provides 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 and increase transparency in the planning process. In addition, our midstream business generates free cash flow, provides optionality and further diversifies our customer base through midstream services we provide to other companies.
Exploration and Production Operations
Proved reserves
Our estimated net proved reserves and related PV-10 at December 31, 2020, 2019 and 2018 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, 2020, 2019 and 2018 in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in crude oil and natural gas
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producing activities. Our estimated net proved reserves and related future net revenues, PV-10 and standardized measure of discounted future net cash flows (“Standardized Measure”) do not include probable or possible reserves and were determined using the preceding 12 months’ unweighted arithmetic average of the first-day-of-the-month index prices for crude 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 12 months were $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas, $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas and $65.66 per Bbl for crude oil and $3.16 per MMBtu for natural gas for the years ended December 31, 2020, 2019 and 2018, 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 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 crude 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.
The following table summarizes our estimated net proved reserves and related future net revenues, Standardized Measure and PV-10:
At December 31,
2020 2019 2018
Estimated proved reserves:
Crude oil (MMBbls) 119.8 200.8 228.4
Natural gas (Bcf) 376.2 513.5 552.7
Total estimated proved reserves (MMBoe) 182.5 286.4 320.5
Percent crude oil 66 % 70 % 71 %
Estimated proved developed reserves:
Crude oil (MMBbls) 85.4 113.4 144.5
Natural gas (Bcf) 262.7 314.0 339.4
Total estimated proved developed reserves (MMBoe) 129.2 165.8 201.1
Percent proved developed 71 % 58 % 63 %
Estimated proved undeveloped reserves:
Crude oil (MMBbls) 34.3 87.4 83.9
Natural gas (Bcf) 113.5 199.5 213.3
Total estimated proved undeveloped reserves (MMBoe) 53.3 120.6 119.4
Future net revenues (in millions) $ 1,793.6 $ 5,385.4 $ 8,341.6
Standardized Measure (in millions) (1)
$ 948.9 $ 2,844.4 $ 4,050.3
PV-10 (in millions) (2)
$ 1,115.0 $ 2,934.4 $ 4,674.3
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(1) Standardized Measure represents the present value of estimated future net cash flows from proved crude 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. See “Reconciliation of Standardized Measure to PV-10” below.
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The following table provides additional information regarding our estimated net proved developed and undeveloped crude oil and natural gas reserves by basin as of December 31, 2020:
Proved Developed Proved Undeveloped
Crude oil (MMBbls) Natural gas (Bcf) Total
(MMBoe) Crude oil (MMBbls) Natural gas (Bcf) Total
(MMBoe)
Williston Basin 72.3 241.9 112.6 23.3 97.2 39.6
Permian Basin 13.2 20.8 16.6 11.0 16.3 13.7
Total 85.5 262.7 129.2 34.3 113.5 53.3
Estimated net proved reserves at December 31, 2020 were 182.5 MMBoe, a 36% decrease from estimated net proved reserves of 286.4 MMBoe at December 31, 2019, primarily due to decreases of 86.3 MMBoe for net negative revisions and 23.7 MMBoe for production, partially offset by an increase of 6.0 MMBoe for additions. The net negative revisions were attributable to negative revisions of 54.5 MMBoe associated with alignment to the five-year development plan and 31.9 MMBoe due to lower realized prices, offset by positive revisions of 1.1 MMBoe due to lower operating expenses.
Our proved developed reserves decreased 36.6 MMBoe, or 22%, to 129.2 MMBoe for the year ended December 31, 2020 from 165.8 MMBoe for the year ended December 31, 2019, primarily due to decreases of 27.8 MMBoe for net negative revisions and 23.7 MMBoe for production, partially offset by increases from our 2020 development program, which included 69 gross (34.6 net) wells that were completed and brought on production during 2020 and resulted in conversions of proved undeveloped reserves of 11.7 MMBoe and additions of 3.2 MMBoe. Proved developed revisions were primarily due to negative revisions of 29.3 MMBoe due to lower realized prices, partially offset by positive revisions of 1.5 MMBoe due to lower operating expenses.
Our proved undeveloped reserves decreased 67.4 MMBoe, or 56%, to 53.3 MMBoe for the year ended December 31, 2020 from 120.6 MMBoe for the year ended December 31, 2019 primarily due to net negative revisions of 58.4 MMBoe and the conversion of wells to proved developed of 11.7 MMBoe, offset by additions of 2.8 MMBoe. The proved undeveloped revisions were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the anticipated five-year development plan and 2.6 MMBoe due to lower realized prices.
See Note 27 to our consolidated financial statements for more information on our proved reserves for the years ended December 31, 2019 and 2018. For the comparison of the years ended December 31, 2019 and 2018, refer to “Item 1. Business—Our operations - exploration and production activities” in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 27, 2020.
Reconciliation of Standardized Measure to PV-10
PV-10 is derived from Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of Standardized Measure on a pre-tax basis. PV-10 is equal to Standardized Measure 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 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 without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and gas properties. PV-10, however, is not a substitute for Standardized Measure. Our PV-10 measure and Standardized Measure do not purport to represent the fair value of our crude oil and natural gas reserves.
The following table provides a reconciliation of Standardized Measure to PV-10:
At December 31,
2020 2019 2018
(In millions)
Standardized Measure of discounted future net cash flows $ 948.9 $ 2,844.4 $ 4,050.3
Add: present value of future income taxes discounted at 10% 166.1 90.0 624.0
PV-10 $ 1,115.0 $ 2,934.4 $ 4,674.3
The PV-10 of our estimated net proved reserves at December 31, 2020 was $1,115.0 million, a 62% decrease from PV-10 of $2,934.4 million at December 31, 2019. This decrease was primarily due to lower commodity price assumptions and a decrease in reserves year over year.
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Proved undeveloped reserves
At December 31, 2020, we had approximately 53.3 MMBoe of proved undeveloped reserves as compared to 120.6 MMBoe at December 31, 2019. The following table summarizes the changes in our proved undeveloped reserves during 2020:
Year Ended December 31, 2020
(MBoe)
Proved undeveloped reserves, beginning of period 120,625
Extensions, discoveries and other additions 2,780
Revisions of previous estimates (58,426)
Conversion to proved developed reserves (11,726)
Proved undeveloped reserves, end of period 53,253
During 2020, we spent a total of $115.5 million related to the development of proved undeveloped reserves, $31.6 million of which was spent on proved undeveloped reserves that represent wells in progress at year-end. The remaining $83.9 million resulted in the conversion of 11.7 MMBoe of proved undeveloped reserves, or 10% of our proved undeveloped reserves balance at the beginning of 2020, to proved developed reserves. We added 2.8 MMBoe of proved undeveloped reserves as a result of our five-year development plan. The 2020 proved undeveloped revisions of 58.4 MMBoe were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the anticipated five-year development plan and 2.6 MMBoe due to lower realized prices.
We expect to develop all of our proved undeveloped reserves, including all wells drilled but not yet completed, as of December 31, 2020 within five years. 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, the Oasis Credit Facility 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 21% of our proved undeveloped reserves at December 31, 2020 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 and Permian Basins.
Independent petroleum engineers
Our estimated net proved reserves and related future net revenues and PV-10 at December 31, 2020, 2019 and 2018 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 (Revised June 2019) and definitions and current guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Moscow, Astana, Buenos Aires, Baku and Algiers. The firm’s more than 180 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 85 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, is a member of the Society of Petroleum Engineers and has over 10 years of experience in crude oil and natural gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Istanbul Technical University in 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005 and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any crude oil, natural 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 crude oil and natural gas producing activities, proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much more likely to be achieved than not, and probabilistically, 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
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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.
A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (i) production diagnostics, (ii) decline-curve analysis and (iii) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history and appropriate reserves definitions.
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 and Chief Engineer, is the technical person primarily responsible for overseeing our reserves evaluation process. He has over 30 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 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, price and cost history
We produce and market crude oil, natural gas and NGLs, which are commodities. The price that we receive for the crude oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, access to markets, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under
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supply of crude oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, natural gas and NGLs, 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 crude oil and natural gas production by basin, realized prices and production costs for the periods presented. For additional information on price calculations, please see information set forth in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Successor Predecessor
Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31,
2019 2018
Net production volumes:
Williston Basin
Crude oil (MBbls) 1,336 11,858 20,722 21,786
Natural gas (MMcf) 4,644 38,844 52,813 40,550
Oil equivalents (MBoe) 2,111 18,331 29,524 28,544
Average daily production (Boepd) 50,256 56,579 80,889 78,203
Permian Basin
Crude oil (MBbls) 257 2,368 2,102 1,264
Natural gas (MMcf) 364 3,355 3,093 1,880
Oil equivalents (MBoe) 317 2,927 2,618 1,578
Average daily production (Boepd) 7,553 9,033 7,172 4,322
Average sales prices:
Crude oil (per Bbl)
Williston Basin $ 42.98 $ 37.04 $ 55.30 $ 62.21
Permian Basin 45.30 35.30 54.96 55.52
Total average sales price 43.36 36.75 55.27 61.84
Total average realized price after the effect of derivative settlements (1)
43.36 48.13 55.89 52.65
Natural gas (per Mcf)
Williston Basin 3.54 2.00 2.70 3.91
Permian Basin 2.56 0.94 1.48 3.29
Total average sales price (2)
3.47 1.91 2.64 3.88
Total average realized price after the effect of derivative settlements (1)(2)
3.45 1.91 2.72 3.84
Average costs (per Boe):
Production costs (3)
Williston Basin $ 11.81 $ 9.96 $ 11.04 $ 10.08
Permian Basin 6.44 7.39 10.10 8.31
Total
Lease operating expenses 7.35 5.57 6.95 6.44
Gathering, processing and transportation expenses 3.76 4.04 4.01 3.56
Production taxes 2.45 2.14 3.50 4.44
E&P general and administrative expenses 5.04 5.92 3.39 3.63
E&P Cash G&A (4)
5.04 4.41 2.07 2.48
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(1) Average realized prices after the effect of derivative settlements include the cash received or paid for the cumulative gains or losses on our commodity derivatives settled in the periods presented, but do not include proceeds from
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derivative liquidations. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.
(2) Natural gas prices include the value for natural gas and NGLs.
(3) Production costs include lease operating expenses and gathering, processing and transportation (“GPT”) expenses.
(4) E&P Cash G&A, a non-GAAP financial measure, represents general and administrative (“G&A”) expenses less non-cash equity-based compensation expenses and other non-cash charges included in our E&P segment. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for a reconciliation of G&A expenses to E&P Cash G&A.
Acreage
The following table sets forth certain information regarding the developed and undeveloped acreage by basin in which we own a working interest as of December 31, 2020. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
Developed acres Undeveloped acres Total
Gross Net Gross Net Gross Net
Williston Basin 466,649 355,203 78,459 46,563 545,108 401,766
Permian Basin 27,431 16,162 12,748 8,234 40,179 24,396
Total 494,080 371,365 91,207 54,797 585,287 426,162
Our total acreage that is held by production decreased to 411,652 net acres at December 31, 2020 from 415,206 net acres at December 31, 2019 .
The following table sets forth the number of gross and net undeveloped acres by basin as of December 31, 2020 that will expire over the next three years unless production is established on the acreage prior to the expiration dates:
Year ending December 31,
2021 2022 2023
Gross Net Gross Net Gross Net
Williston Basin 6,030 5,769 3,599 1,108 262 161
Permian Basin 1,794 879 110 13 40 6
Total 7,824 6,648 3,709 1,121 302 167
Productive wells
The following table presents the total and operated gross and net productive wells by basin as of December 31, 2020:
Total wells Operated wells
Gross Net Gross Net
Williston Basin - horizontal wells 1,491 870.6 1,127 827.9
Williston Basin - other — — — —
Permian Basin - horizontal wells 172 54.1 57 53.4
Permian Basin - other 17 6.4 4 3.2
Total wells 1,680 931.1 1,188 884.5
All of our productive wells are crude 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.
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Drilling and completion activity
The following table summarizes the number of gross and net wells completed during the periods presented, regardless of when drilling was initiated.
Year ended December 31,
2020 2019 2018
Gross Net Gross Net Gross Net
Development wells:
Oil 69 34.6 123 46.2 135 84.2
Gas — — — — — —
Dry — — — — — —
Total development wells 69 34.6 123 46.2 135 84.2
Exploratory wells:
Oil — — 7 5.9 2 1.3
Gas — — — — — —
Dry — — — — — —
Total exploratory wells — — 7 5.9 2 1.3
Total wells 69 34.6 130 52.1 137 85.5
As of December 31, 2020, we had 61 gross (29.3 net) wells in the process of being drilled or completed, which includes 32 gross operated wells waiting on completion and 29 gross non-operated wells drilling or completing.
As of December 31, 2020, we had one operated rig running in the Williston Basin, and in 2021, we expect to continue running one operated rig in the Williston Basin and to add an operated rig in the Permian Basin later this year, while concentrating drilling activities within our top-tier acreage.
Description of properties
Williston Basin
Our position in the North Dakota and Montana areas of the Williston Basin is our cornerstone asset. We are one of the top producers in the Williston Basin and have been active in the area since our formation. 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. Production in the Williston Basin primarily comes from two zones: the Middle Bakken and the Three Forks. Our development activity is currently focused on our top-tier operated acreage in the deepest part of the Williston Basin in McKenzie, Mountrail and Williams counties in North Dakota.
As of December 31, 2020, our total leasehold position in the Williston Basin consisted of 401,766 net acres, and we had a total of 870.6 net producing wells and 827.9 net operated producing wells in the Williston Basin. During the year ended December 31, 2020, we had average daily production of 55,853 net Boepd in the Williston Basin, 100% of which was produced from horizontal wells. As of December 31, 2020, our working interest for producing horizontal wells averaged 58% in total and 73% in the wells we operate.
Permian Basin
We entered the Permian Basin in February 2018 when we closed on an acquisition of approximately 22,000 net acres primarily located in the Bone Spring and Wolfcamp formations of the Delaware sub-basin, across Ward, Winkler, Loving and Reeves counties in West Texas (the “2018 Permian Acquisition”). Our advanced geologic position in the Permian Basin results in an over 80% oil mix and has multi-stacked pay zones, with four primary stacked zones counted in our core inventory and potential upside from four additional zones.
As of December 31, 2020, our total leasehold position in the Permian Basin consisted of 24,396 net acres, and we had a total of 60.5 net producing wells and 56.6 net operated producing wells in the Permian Basin. During the year ended December 31, 2020, we had average daily production of 8,864 net Boepd in the Permian Basin, of which 99%, or 8,818 net Boepd, was produced from horizontal wells. As of December 31, 2020, we had 53.4 net operated producing horizontal wells in the Permian Basin, and our working interest for producing horizontal wells in the Permian Basin averaged 31% in total and 94% in the wells we operate.
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Continuous development agreement. In connection with the closing of the 2018 Permian Acquisition, Forge Energy, LLC (“Forge Energy”) entered into and assigned to OP Permian a continuous development agreement (the “CDA”) 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 (together with the State, “University Lands”). The CDA concerns certain leases covering a substantial portion of the acreage that we indirectly acquired from Forge Energy in the 2018 Permian Acquisition and under which University Lands is the lessor. Pursuant to the CDA, the tracts covered by these leases are pooled into a single development area for which we indirectly hold 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 Spring and Wolfcamp formations. If OP Permian fails to meet certain drilling and development obligations, the CDA may be subject to early termination, in which case, we may be obligated to pay non-performance fees of up to approximately $100 million. See “Item 1A. Risk Factors—Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed. 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.” Due to the extraordinary market conditions during 2020, we agreed with University Lands to pause operations, and on December 31, 2020, we executed an amendment to the CDA reflecting that agreement. The amendment reduced or postponed certain drilling and development obligations for the year ended December 31, 2020 and did not result in the payment of any penalty. Our current budget contemplates drilling activity which does not meet certain obligations under the CDA. We are currently in discussions with University Lands, similar to those held in 2020, in which we will seek an amendment for the reduction of our drilling obligations for 2021 similar to that previously received. We can provide no assurance that we will be successful in obtaining this amendment. Given the early stages of our discussions with University Lands on our drilling obligations for 2021 and the continuous flexibility we have with our drilling program to adjust as market and business conditions warrant, we cannot predict whether we will incur losses or estimate the amount of any potential loss.
Marketing and major customers
We principally sell our crude oil, natural gas and NGL production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities. In an effort to improve price realizations from the sale of our crude oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil and natural gas to a broad array of potential purchasers. We sell a significant amount of our crude oil production through bulk sales at delivery points on crude oil gathering systems 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. These gathering systems, which typically originate at the wellhead and are connected to multiple pipeline and rail facilities, reduce the need to transport barrels by truck from the wellhead. As of December 31, 2020, we were flowing approximately 92% of our gross operated crude oil production through crude oil gathering systems, including 93% of our gross operated crude oil production in the Williston Basin and 81% of our gross operated crude oil production in the Permian Basin. In addition, from time to time we may enter into third-party purchase and sales transactions that allow us to optimize our advantageous gathering and transportation positions and increase the value of our crude oil price realizations. We also enter into various short-term sales contracts for a portion of our portfolio at fixed differentials.
Our marketing of crude oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—The marketability of our production is dependent upon crude oil, natural gas and NGL gathering, processing and transportation facilities, some of which are owned by third parties. Market conditions or operational impediments could hinder our access to crude oil, natural gas or NGL markets, delay our production or reduce the realized prices we receive.”
For the Successor period of November 20, 2020 through December 31, 2020, sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22% and 15%, respectively, of our total product sales. For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11% and 10%, respectively, of our total product sales. For the year ended December 31, 2019, sales to Phillips 66 Company accounted for approximately 14% of our hydrocarbon product sales. No other purchasers accounted for more than 10% of our total sales in 2020 or 2019. For the year ended December 31, 2018, no purchaser accounted for more than 10% of our total sales. 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, natural gas and NGL purchasers and markets in the Williston and Permian Basins.
Delivery commitments
As of December 31, 2020, we had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 46.6 MMBbl of crude oil, 704.1 Bcf of natural gas and 28.1 MMBbl of NGLs, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less, except for one agreement with a remaining term of approximately 24 years. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum
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volume commitments under certain agreements. We believe that our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, natural gas and NGLs from third parties to satisfy our minimum volume commitments.
Midstream Operations
Our midstream business provides full service midstream solutions including natural gas services (gathering, compression, processing and gas lift supply), crude oil services (gathering, terminaling and transportation) and water services (gathering and disposal of produced and flowback water and freshwater distribution).
Our midstream operations are primarily conducted through OMP, a consolidated subsidiary and master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets. OMP conducts its operations through its four development companies: Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth DevCo”) and Panther DevCo LLC. At December 31, 2020, our ownership interest in OMP consisted of a 67.5% limited partner interest, a 92% controlling interest in OMP GP LLC (“OMP GP”), which owns all of OMP’s incentive distribution rights and its non-economic general partner interest, and our retained interests in Bobcat DevCo and Beartooth DevCo of 64.7% and 30%, respectively.
Our midstream assets are strategically located with our exploration and development activities in the Williston and Permian Basins and support our upstream operations. We have several long-term contractual arrangements with OMP, pursuant to which we have dedicated significant acreage to OMP for midstream services. We have approved an expansion of our acreage dedication to OMP in South Nesson, one of our top operating areas in the Williston Basin, to now include crude oil and produced water services. We previously dedicated our South Nesson acreage to OMP for natural gas services in 2019. OMP expects volumes under each service offering to flow in 2022. As part of the arrangement, we agreed to assign to Bighorn DevCo, which is 100% owned by OMP, certain assets in Bobcat DevCo specifically built to support both existing third-party customers in South Nesson and our future development. All future midstream infrastructure in South Nesson will be built by Bighorn DevCo, which will perform, and earn the revenue for, all of OMP’s future midstream services in the area.
In addition, OMP provides services to third-party customers and has received certain commitments from third parties in both the Williston and Permian Basins, in which OMP has the right to provide its full suite of midstream services to support existing and future third-party volumes.
Competition
The oil and gas industry is worldwide and highly competitive in all phases. We encounter competition from other crude oil and natural gas companies in all areas of operation, including the acquisition of leasing options on oil and gas properties to the exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies, numerous independent crude 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 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 Factors—Risks related to the oil and gas industry and our business—Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.”
Title to Properties
As is customary in the crude 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 crude oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and gas properties are subject to customary royalty and other interests, liens to secure borrowings under the Oasis Credit Facility, 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 Factors—Risks related to the oil and gas industry and our business—We may incur losses as a result of title defects in the properties in which we invest.”
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Seasonality
Winter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities and other crude 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
Our E&P and midstream operations are substantially affected by federal, tribal, regional, state and local laws and regulations. In particular, crude oil and natural gas production, crude oil gathering and transportation, natural gas processing and related operations are, or have been, subject to price controls, taxes and numerous laws and regulations. All of the jurisdictions in which we own or operate properties for crude oil and natural gas production or otherwise provide midstream services have statutory provisions regulating the exploration for and production of crude 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 that may be drilled in an area, the siting of processing plants, disposal wells and gathering or transportation lines, and the unitization or pooling of crude 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, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may occur and, thus, there can be no assurance that such costs will not be material in the future. 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 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 be finalized and become effective.
Regulation of transportation and sales of crude oil
Sales of crude oil, condensate and NGLs 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 crude oil by common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate crude 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 crude oil pipelines that allows a pipeline to increase its rates annually up to prescribed ceiling levels that are tied to changes in the Producer Price Index, without making a cost of service filing. Many existing pipelines utilize the FERC crude oil index to change transportation rates annually every July 1, and our Bighorn DevCo Johnson’s Corner line will utilize the FERC crude oil index beginning on July 1, 2022. Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs. Most recently, on December 17, 2020, FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index plus 0.78%. FERC has received requests for rehearing of its December 17, 2020 order, which remain pending in FERC Docket No. RM20-14-000.
Intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude 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 crude 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 crude 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
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terms and under the same rates. When crude 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 crude 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. Due to several crude oil train derailments in the past decade, transportation safety regulators in the United States and Canada have examined the adequacy of transporting crude oil by rail, with an emphasis on the safe transport of Bakken crude oil by rail, following findings by the U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that Bakken crude oil tends to be more volatile and flammable than certain other crude oils, and thus poses an increased risk for a significant accident.
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 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, new operational protocols for trains transporting large volumes of flammable liquids and a requirement that older DOT-111 tank cars be phased out beginning in October 2017 if they are not already retrofitted to comply with new tank car design standards. In 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, and more recently in February 2019, PHMSA published a final rule requiring railroads to develop and submit comprehensive oil spill response plans for specific route segments traveled by 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. Additionally, the February 2019 final rule requires railroads to establish geographic response zones along various rail routes, ensure that both personnel and equipment are staged and prepared to respond in the event of an accident, and share information about high-hazard flammable train operations with state and tribal emergency response commissions.
In addition, a number of states proposed or enacted laws in recent years that encourage safer rail operations, urge the federal government to strengthen requirements for these operations or otherwise seek to impose more stringent standards on rail transport of crude oil. For example, in the absence of a current federal standard on the vapor pressure of crude oil transported by rail, the State of Washington passed a law that became effective in July 2019, prohibiting the loading or unloading of crude oil from a rail car in the state unless the crude oil vapor pressure is lower than 9 pounds per square inch. In response, the States of North Dakota and Montana filed a preemption application with PHMSA in July 2019and in May 2020, PHMSA published a Notice of Administrative Determination of Preemption, finding that the federal Hazardous Material Transportation Law preempts Washington State’s vapor pressure limit was preempted under applicable federal law.
One or more of these federal or state safety improvements or updates relating to rail tank cars and rail crude oil-related operational practices imposed by PHMSA since 2015 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 rules or that restrictions on rail transport of crude oil due to state crude oil volatility standards, if not preempted by PHMSA, 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.
More stringent regulatory initiatives have likewise been pursued in Canada to assess and address risks from the transport of crude oil by rail. For example, since 2014, Transport Canada has issued requirements prohibiting crude oil shippers from using certain DOT-111 tank cars and imposed a phase out schedule for other tank cars that do not meet specified safety requirements, 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. Also, at or near 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 aligned with the requirements in the PHMSA rule and issued retrofitting and phase out timelines similar to those introduced by PHMSA. Transport Canada 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, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement regarding hazardous material transportation may occur in the future, which 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 PHMSA and Transport Canada standards and regulations emerging from these existing and any future rulemakings will not be material to our business, financial condition or results of operations. In addition, any derailment of crude oil from the Williston or Permian Basins 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
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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 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, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. 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, 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 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, 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 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 established by 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 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 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 FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, 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.
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Regulation of production
The production of crude oil, natural gas and NGLs 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, Montana and Texas, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from crude 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 crude 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, all three states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and NGLs within their jurisdictions.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and 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
The Energy Policy Act of 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 FERC with the power to assess civil penalties of up to $1,307,164 per day, adjusted annually for inflation, for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,307,164 per violation per day, adjusted annually for inflation. 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 increased 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.
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 $1,246,249 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.
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Texas Railroad Commission crude oil and natural gas rules
The Texas Railroad Commission (the “RRC”), through its Oil and Gas Division, regulates the exploration, production and transportation of crude oil and natural gas in Texas. Among other duties, the RRC develops and adopts regulations to prevent waste of the state’s crude oil and natural resources, protects the correlative rights of different interest owners, prevents pollution and provides safety with respect to operations including, for example, hydrogen sulfide emissions. The RRC grants drilling permits based on established spacing, density and special field rules. Additionally, each month, the RRC assigns production allowables on crude oil and natural gas wells based on factors such as tested well capability, reservoir mechanics, market demand for production and past production, as well as receives operators’ production reports on crude oil leases and gas wells and audits the crude oil disposition path to ensure production did not exceed allowables. The RRC also regulates crude oil field injection and disposal wells under a federally-approved program that includes permitting, annual reporting and periodic testing activities. Through this program, fluids are injected into either productive reservoirs under enhanced recovery projects to increase production or into productive or non-productive reservoirs for disposal. In other pollution prevention activities, the RRC assures waste management is carried out by permitting pits and landfarming, discharges, waste haulers, waste minimization and hazardous waste management tasks. To prevent pollution of the state’s surface and ground water resources, the RRC has an abandoned well plugging and abandoned site remediation program that uses funds provided by industry through fees and taxes. Wells and sites are remediated with funds from this program when responsible operators cannot be found. Moreover, flaring of natural gas is subject to regulation by the RRC under its rules, but those rules allow for permitted exceptions through the use of flare permits. Flaring may provide crude oil and natural gas producers with an approved means for continuing crude oil production under certain scenarios, such as, for example, when there may be insufficient pipeline infrastructure in place to transport natural gas to market or to prevent resource waste. The imposition of more stringent requirements by the RRC or as a result of litigation contesting such flare permit practice that lessen producers’ opportunities to flare under RRC permitted exceptions could result in reduced production, which development could have an adverse effect on our and similarly situated producers’ business and results of operations.
North Dakota Industrial Commission crude oil and natural gas rules
The North Dakota Industrial Commission (the “NDIC”) regulates the drilling and production of crude oil and natural gas in North Dakota. Beginning in 2012 and continuing thereafter, the NDIC has adopted more stringent rules relating to production activities, including with respect to financial assurance for wells and underground gathering pipelines, waste discharges and storage, hydraulic fracturing and associated public disclosure on the FracFocus chemical disclosure registry, site construction, underground gathering pipelines and spill containment, which new requirements are now in effect. These requirements have increased or will increase the well costs incurred by us and similarly situated crude oil and natural gas E&P operators, and we expect to continue to incur these increased costs as well as any added costs arising from new NDIC legal requirements laws and regulations applicable to the drilling and production of crude oil and natural gas that may be issued in the future.
Furthermore, the NDIC regulates natural gas flaring and over the past decade has issued orders limiting flaring emissions. These requirements were further revised in 2020. Please see below the discussion of “Environmental protection and natural gas flaring initiatives” for more information on the natural gas flaring program. In addition, the NDIC has adopted rules that improve the safety of Bakken crude oil for transport by establishing operating standards for conditioning equipment to properly separate production fluids, limits to the vapor pressure of produced crude oil, and parameters for temperatures and pressures associated with the production equipment.
Pipeline safety regulation
Certain of our pipelines are subject to regulation by PHMSA under the Hazardous Liquids Pipeline Safety Act (“HLPSA”) with respect to crude 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 hazardous liquid and gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to develop and implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas (“HCA”) and moderate consequence areas (“MCA”) along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gas pipelines are predicated on high-population areas (which, for natural gas transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for crude oil, NGL and condensate pipelines are based on high-population areas, certain drinking water sources and unusually sensitive ecological areas. An MCA is attributable to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipeline HCA. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate 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 pipeline safety laws or regulations, amendment of existing
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laws and regulations, reinterpretation of legal requirements or increased governmental enforcement 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 restrictions, delays or cancellations.
Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the HLPSA and NGPSA were amended by the Pipeline, Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2016. 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. The PIPES Act of 2016 extended PHMSA’s statutory mandate and, among other things, required PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities. The PIPES Act of 2016 also empowers PHMSA to address unsafe conditions or practices constituting imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or gas pipeline facilities without prior notice or an opportunity for a hearing. More recently, Congress passed the Fiscal Year 2021 Omnibus Appropriations Bill, made effective on December 27, 2020, pursuant to which Congress adopted the PIPES Act of 2020. The PIPES Act of 2020 reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions that, among other things, will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.
New 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 restrictions, delays or cancellations. In October 2019, PHMSA published a final rule, made effective July 2020, that significantly extends and expands the reach of certain PHMSA hazardous liquid integrity management requirements, such as, for example, performance of periodic assessments and expanded use of leak detection systems, regardless of the pipeline’s proximity to a HCA (for example, integrity assessments at least once every 10 years for onshore, piggable, hazardous liquid pipeline segments located outside of HCAs, and expanded use of leak detection systems outside of HCAs on all regulated hazardous liquid pipelines other than offshore gathering and regulated rural gathering pipelines). Additionally, this final rule requires all hazardous liquid pipelines in or affecting a HCA to be capable of accommodating in-line inspection tools within the next 20 years unless the basic construction of a pipeline cannot be modified to permit that accommodation. Moreover, this final rule extends annual, accident, and safety-related conditional reporting requirements to hazardous liquid gravity lines and certain gathering lines and also imposes inspection requirements on hazardous liquid pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure.
Also, in October 2019, PHMSA published the first of three expected regulations relating to new or more stringent requirements for certain natural gas pipelines, that had originally been proposed in 2016 as part of PHMSA’s “gas Mega Rule,” which first final rule became effective on July 1, 2020, and imposed numerous requirements, including maximum allowable operating pressure (“MAOP”) reconfirmation through re-verification of all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (including all MCAs and those Class 3 and Class 4 areas found not to be in HCAs) within 14 years of publication date and at least once every 10 years thereafter, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management. We are currently evaluating the operational and financial impact related to this final rule. The remaining rulemakings comprising the gas Mega Rule have not yet been published, and we cannot predict when they will be finalized; however, they are expected to include revised pipeline repair criteria as well as more stringent corrosion control requirements. New legislation or any new 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, crude 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
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to reclaim and abandon well sites, pits, processing plants and pipelines; and impose specific criteria addressing worker protection. Certain environmental laws impose joint and several strict liability for costs required to remediate and restore sites where hydrocarbons, materials or wastes have been stored or released. 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 restrictions, delays or cancellations in the permitting, 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 crude 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 new laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement 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. We may also experience a delay in obtaining or be unable to obtain required permits, which may interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. 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 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. Some or all of such increased compliance costs may not be recoverable from insurance.
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 (the “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 crude oil and natural gas from regulation as hazardous wastes. These wastes are instead regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. There have been efforts from time to time to remove this exclusion, which removal could significantly increase our and our customers operating costs, and it is possible that certain crude oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future.
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 crude 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,
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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 (the “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 certain pollutants. Obtaining permits has the potential to restrict, delay or cancel the development or expansion of crude 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 2015, the EPA under the Obama Administration issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-level ozone, and, on December 31, 2020, published a notice of final action to retain the 2015 ozone NAAQS without revision on a going-forward basis, but this December 2020 final action is subject to legal challenge, and the NAAQS may be subject to further revision under the Biden Administration. States are expected to implement more stringent regulations that could apply to our operations. 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 crude oil and natural gas that we produce, which one or more developments could adversely impact our E&P and midstream businesses.
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 recognize the environmental and financial risks associated with air emissions, particularly with respect to flaring of natural gas from our operated well sites and are focused on reducing these emissions, consistent with applicable requirements.
We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is a historical lack of natural gas gathering infrastructure in the Williston Basin, which translates into the inability of operators to promptly connect their wells to natural gas processing and gathering infrastructure. External factors impacting such inability that are out of the control of the operator include, 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. We have allocated significant resources to connect our wells to natural gas infrastructure. In both the Williston and Permian Basins, the substantial majority of our operated wells are connected to gas gathering systems, which minimizes our flared volumes of natural gas.
The NDIC has issued orders and pursued other regulatory initiatives to implement legally enforceable “gas capture percentage goals” targeting the capture of natural gas produced in the state, commencing in October 2014. As of November 1, 2020, the enforceable gas capture percentage goal is 91%. The NDIC requires operators to develop and implement Gas Capture Plans to maintain consistency with the agency’s gas capture percentage goals, but it maintains the flexibility to exclude certain gas volumes from consideration in calculating compliance with the state’s gas capture percentage goals. Wells must continue to meet or exceed the NDIC’s gas capture percentage goals on a statewide, county, per-field, or per-well basis. Failure of an operator to comply with the applicable goal at maximum efficiency rate may result in the imposition of monetary penalties and restrictions on production from subject wells. Most recently, in September 2020, the NDIC revised the gas capture policy to allow several additional exceptions for companies that flare natural gas under certain circumstances, such as gas plant outages or delays in securing a right-of-way for pipeline construction, but did not change the gas capture targets. As of December 31, 2020, we were capturing approximately 96% of our natural gas production in North Dakota, and our flared gas percentage is two-thirds less than the average for North Dakota operators. While we were satisfying the applicable gas capture percentage goals as of December 31, 2020, 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
In the United States, no comprehensive climate change legislation has been implemented at the federal level, but President Biden has announced plans to take action with regards to climate change, has already signed several executive orders to this effect in January 2021 and, with control of Congress shifting in January 2021, is expected to pursue legislative as well as other executive and regulatory initiatives in the future to limit greenhouse gas (“GHG”) emissions. Moreover, because the U.S.
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Supreme Court has held that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement New Source Performance Standards (“NSPS”) directing the reduction of methane from certain new, modified or reconstructed facilities in the crude oil and natural gas sector, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States.
In recent years, there has been considerable uncertainty surrounding regulation of methane emissions, as the EPA under the Obama Administration published final regulations under the CAA establishing new performance standards for methane in 2016, but since that time the EPA under the Trump Administration undertook several measures, including publishing in September 2020 final rule policy and technical amendments to the NSPS, for stationary sources of air emissions. The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and volatile organic compound (“VOC”) requirements for the remaining sources that were established by the Obama Administration, whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA’s September 2020 final rules, and on January 20, 2021, President Biden issued an executive order, that among other things, directed the EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding those amendments by no later than September 2021. A reconsideration of the September 2020 policy amendments is expected to follow. The January 20, 2021 executive order also directed the establishment of new methane and VOC standards applicable to existing crude oil and natural gas operations, including the production, transmission, processing and storage segments.
Separately, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. At the international level, the non-binding Paris Agreement requests that nations limit their GHG emissions through individually-determined reduction goals every five years after 2020. Although the U.S. had withdrawn from the Paris Agreement, President Biden has issued executive orders recommitting the U.S. to the Paris Agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction goal under the agreement. With the U.S. recommitting to the Paris Agreement, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the Paris Agreement’s goals.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States. On January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends new crude oil and natural gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. Building on this suspension, President Biden issued an executive order on January 27, 2021 that suspends new leasing activities for crude oil and natural gas E&P on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal crude oil and natural gas permitting and leasing practices. The January 20, 2021 and January 27, 2021 orders do not apply to existing leases but the January 27, 2021 order further directs applicable agencies to take measures to eliminate subsidies provided to the fossil fuel industry. These suspensions are subject to legal challenge, with at least one industry group filing a lawsuit in January 2021, in Wyoming federal district court and seeking to have the moratorium declared invalid.
Litigation risks are also increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against the largest crude oil and natural gas E&P companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. There are also increasing financial risks for fossil fuel producers as well as other companies handling fossil fuels, including owners of terminals, pipelines and refineries, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies, as President Biden signed an executive order in January 2021 calling for, among other things, the development of a climate finance plan and, separately, the Federal Reserve announced in December 2020 that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.
Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events.
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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. In 2015, the EPA and U.S. Army Corps of Engineers (the “Corps”) under the Obama Administration published a final rule that would significantly expand the scope of the Clean Water Act over waters of the United States, including wetlands. However, the EPA and the Corps under the Trump Administration issued a final rule, made effective in December 2019, that repealed the 2015 rule and they also published a final rule in April 2020 re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation. The April 2020 final rule is subject to various pending legal challenges; moreover, there is an expectation with the Biden Administration taking office in January 2021, there is a possibility that the new administration will review and may reconsider this April 2020 final rule. If the EPA and the Corps under the Biden Administration revise the April 2020 final rule in a manner similar to or more stringent than the 2015 final rule, or if any challenge to the April 2020 final rule is successful, the scope of the Clean Water Act’s jurisdiction in areas where we conduct operations could again be expanded and result in increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Any such developments could delay, restrict or halt permitting or development of projects, result in longer permitting timelines, or increase compliance expenditures or mitigation costs for our operations.
The Oil Pollution Act of 1990 (the “OPA”) amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of crude 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 crude oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from crude 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 crude 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 (the “SDWA”) Underground Injection Control (the “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.
In response to seismic events near underground injection wells used for the disposal of produced water from crude oil and natural gas activities, federal and some state agencies have investigated, and continue to investigate, whether such wells have caused increased seismic activity. In 2016, the United States Geological Survey identified Texas as being among six states with areas of increased rates of induced seismicity that could be attributed to fluid injection or crude oil and natural gas extraction. Since that time, the United States Geological Survey indicates that these rates have decreased in these states, although concern continues to exist over quakes arising from induced seismic activities. 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 RRC has adopted rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of crude oil and natural 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.
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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 proppants 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 crude oil and natural gas commissions or similar agencies, but federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has 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, as well as published an advance notice of proposed rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. In addition, the EPA has published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional crude oil and natural gas extraction facilities to publicly owned wastewater treatment plants. Moreover, in 2016, the federal Bureau of Land Management (the “BLM”) under the Obama Administration published a final rule imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. However, in late 2018, the BLM under the Trump Administration published a final rule rescinding the 2016 final rule. Litigation challenging the BLM's 2016 final rule as well as its 2018 final rule rescinding the 2016 rule has been pursued by various states and industry and environmental groups. While a California federal court vacated the 2018 final rule in July 2020, a Wyoming federal court subsequently vacated the 2016 final rule in October 2020 and, accordingly, the 2016 final rule is no longer in effect but the Wyoming decision may be appealed. Additionally, in late 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.
From time to time Congress has considered, but has not adopted, legislation to provide for federal regulation of hydraulic fracturing. However, with President Biden taking office and the shift in party control of the Congressional Senate in January 2021, there is a possibility that a Biden Administration will pursue such legislation. In addition to pursuing the revision of existing laws and regulations, President Biden has issued, and may continue to issue, additional executive orders in pursuit of his regulatory agenda with regards to limiting hydraulic fracturing.
In addition, some states, including North Dakota and Texas where we primarily operate, have adopted, and other states may adopt, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. States could elect to adopt certain prohibitions on hydraulic fracturing, following the approach already taken by several states. 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 or bans relating to the hydraulic fracturing process are adopted in areas where we operate, or in the future plan to operate, we could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be limited or precluded from drilling wells or in the volume that we are ultimately able to produce from our reserves.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, crude oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added delays, restrictions or cancellations in the pursuit of our operations or increased operating costs in our production of crude oil and natural gas. 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 (the “ESA”) and comparable state laws 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 (the “MBTA”). The U.S. Fish and Wildlife Service (the “FWS”) under the Trump Administration issued a final rule on January 7, 2021, which notably clarifies that criminal liability under the MBTA will apply only to actions “directed at” migratory birds, their nests or their eggs; however, in 2020, the U.S. District Court for the Southern District of New York vacated a Department of Interior memorandum articulating a similar interpretation. With the new Presidential Administration taking office in January 2021, it is possible that the January 2021 rule will be subject to reconsideration by the Biden Administration or be subject to legal challenges. 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 or endangered 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 wish to conduct seismic surveys, development activities or abandonment
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operations, such work could be prohibited or delayed by seasonal or permanent restrictions or require the implementation of expensive mitigation.
Moreover, the FWS may make determinations on the listing of species as endangered or threatened under the ESA and litigation with respect to the listing or non-listing of certain species as endangered or threatened may result in more fulsome protections for non-protected or lesser-protected species pursuant to specific timelines. The issuance of more stringent conservation measures or land, water, or resource use restrictions could result in operational delays and decreased production and revenue for us and have an indirect adverse impact on the demand for our midstream services.
Operations on federal lands
Performance of crude oil and natural gas E&P activities on federal lands, including Indian lands and lands administered by the 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. On July 16, 2020, the Council on Environmental Quality (the “CEQ”) under the Trump Administration published a final rule modifying NEPA. The modified final rule establishes a time limit of two years for preparation of environmental impact statements and one year for the preparation of environmental assessments. The modified rule also eliminates the responsibility to consider cumulative effects of a project. With the change in Presidential Administrations in January 2021, it is possible that the final rule will be delayed or not implemented as President Biden may have the CEQ under his administration reconsider or withdraw the rule and also because the final rule is being challenged in court.
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, limitations or prohibitions in the scope of crude 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. President Biden has pledged to ban new leases for production of minerals on federal properties, including onshore lands and offshore waters, and recently issued a 60-day suspension of such new leases and drilling permits on federal properties. Approximately 3% of our net acreage position in the Williston Basin is federal mineral acreage, which is spread across our acreage position, and any portion of a well on federal land requires a permit. However, we believe that the vast majority of our future drilling locations are not affected by the need to obtain a federal permit.
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 regulations 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.
Human Capital Resources
As of December 31, 2020, we employed 432 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.
We, as a company and as individuals, believe in “doing the right thing” and being passionate about our work with the goal that we all succeed together (including our employees, contractors, shareholders and the communities in which we operate). We also believe that great people and great assets create great opportunity, and these core values inform how we think about our business.
Health and safety
We are committed to protecting the safety of our employees, our contractors, and the communities in which we operate. We continually seek to develop best-in-class procedures to maintain our safety culture. We operate our worksites under a stop work authority program, under which every person on our worksites is empowered to halt operations to address a potential safety issue. In addition, we have developed and implemented a comprehensive environment, health and safety management system and regularly conduct internal and external audits of our environmental and safety programs, including contractor safety audits.
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Safety training is provided to all employees, and safety performance is integrated into the annual performance-based cash incentive awards for all employees.
During 2020, we launched a proactive response to the COVID-19 pandemic to protect the health and safety of our employees, contractors and the communities in which we operate. We took actions to adhere to recommendations by the Centers for Disease Control and Prevention regarding social distancing and limited public exposure in connection with the COVID-19 pandemic. Even though our operations were not required to close, we adopted a work-from-home system for all office-based employees and deployed additional safety protocols at our operating sites in order to keep the field-based employees and contractors supporting our operations safe while continuing operations running without material disruption. We believe regular and consistent communication with employees is important to establish new procedures and mitigate the spread of COVID-19. In light of the recent resurgence of COVID-19 and evolving data concerning the pandemic, we continue to review the guidelines from federal, state and local officials to promote the safety of our stakeholders.
Compensation and benefits
We seek to provide fair, competitive compensation and comprehensive benefits to our employees. To ensure alignment with our short- and long-term objectives, our compensation programs consist of base pay, short-term incentives and long-term incentives, including stock grants. Our wide array of benefits include retirement plan dollar matching, health insurance for employees and their families, income protection and disability coverage, paid time off, flexible work schedules and wellness resources, including emotional well-being services through an employee Life Assistance Program as well as financial wellness tools and resources.
We invest in leadership training and professional development programs that will enable our employees to reach their potential and perform at their best. Oasis Academy for Success is our on-demand learning system, which supports job-specific training as well as soft skill and leadership development training.
Diversity and inclusion
We recognize that a diverse workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our business succeed, and we are committed to providing a diverse and inclusive workplace to attract and retain talented employees. We maintain a work culture that treats all employees fairly and with respect, promotes inclusivity, and provides equal opportunities for the professional growth and advancement based on merit. Our Code of Business Conduct and Ethics prohibits discrimination or harassment against any employee or applicant on the basis of race, color, gender, religion, age, national origin, citizenship status, military service or veteran status, sexual orientation or disability. In addition, we seek business partners who do not engage in prohibited discrimination in hiring or in their employment practices and who make decisions about hiring, salary, benefits, training opportunities, work assignments, advancement, discipline, termination, retirement and other employment decisions based on job and business-related criteria. To sustain and promote a diverse and inclusive workforce, we maintain a robust compliance program supported by annual certification by all employees to our Code of Business Conduct and Ethics, as well as training programs on affirmative action and equal employment opportunity. We evaluate ways to enhance awareness of and promote diversity and inclusion on an ongoing basis.
Offices
Our principal office is located in Houston, Texas at 1001 Fannin Street. 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. Our filings with the SEC are available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.
We 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.
Other information, such as presentations, the charters of the Audit and Reserves Committee, Compensation Committee and Nominating, Environmental, Social and Governance Committee, and the Code of Business Conduct and Ethics, are available on our website, http://www.oasispetroleum.com, under “Investors — Corporate Governance” and in print to any shareholders who provide a written request to the Corporate Secretary at 1001 Fannin Street, Suite 1500, Houston, Texas 77002.
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Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including the Chief Executive Officer and Chief Financial Officer. Within the time period required by the SEC and The Nasdaq Stock Market LLC (“Nasdaq”), as applicable, we will post on our website any modification to the Code of Business Conduct and Ethics and any waivers applicable to senior officers who are defined in the Code of Business Conduct and Ethics, as required by the Sarbanes-Oxley Act of 2002.
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Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.