Whiting Holdings LLC - Annual Report: 2019 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

or

☐        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to _______________

Commission file number: 001-31899

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Securities registered pursuant to Section 12(b) of the Act:

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Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☒    No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ☐    No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes  ☒    No  ☐

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Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes  ☐    No  ☒

Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2019:  $1,693,000,000.

Number of shares of the registrant’s common stock outstanding at February 20, 2020: 91,813,908 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference into Part III.

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GLOSSARY OF CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we”, “us”, “our” or “ours” when used in this Annual Report on Form 10-K refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries.  When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in this Annual Report on Form 10-K:

“ASC” Accounting Standards Codification.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil, NGLs and other liquid hydrocarbons.

“Bcf” One billion cubic feet, used in reference to natural gas.

“BOE” One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.

“Btu” or “British thermal unit” The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit.

“completion” The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.

“costless collar” An option position where the proceeds from the sale of a call option at its inception fund the purchase of a put option at its inception.  A collar can also contain an additional sold put option.  Refer to “three-way collar” for more information.

“deterministic method” The method of estimating reserves or resources using a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation.

“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“differential” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.

“dry hole” or “dry well” A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

“EOR” Enhanced oil recovery.

“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

“extension well” A well drilled to extend the limits of a known reservoir.

“FASB” Financial Accounting Standards Board.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.  There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both.  Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.  The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

“GAAP” Generally accepted accounting principles in the United States of America.

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“gross acres” or “gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

“ISDA” International Swaps and Derivatives Association, Inc.

“lease operating expense” or “LOE” The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

“LIBOR” London interbank offered rate.

“MBbl” One thousand barrels of oil, NGLs or other liquid hydrocarbons.

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

“Mcf” One thousand cubic feet, used in reference to natural gas.

“MMBbl” One million barrels of oil, NGLs or other liquid hydrocarbons.

“MMBOE” One million BOE.

“MMBtu” One million British Thermal Units, used in reference to natural gas.

“MMcf” One million cubic feet, used in reference to natural gas.

“MMcf/d” One MMcf per day.

“net acres” or “net wells” The sum of the fractional working interests owned in gross acres or wells, as the case may be.

“net production” The total production attributable to our fractional working interest owned.

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

“PDNP” Proved developed nonproducing reserves.

“PDP” Proved developed producing reserves.

“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.  Regulations of most states legally require plugging of abandoned wells.

“pre-tax PV10%” The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated lease operating expense, transportation, gathering, compression and other expense, production taxes and future development costs, using costs as of the date of estimation without future escalation and using an average of the first-day-of-the-month price for each of the 12 months within the fiscal year, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes and discounted using an annual discount rate of 10%.  Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC.  Refer to the footnote to the Proved Reserves table in Item 1. “Business” of this Annual Report on Form 10-K for more information.

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“probabilistic method” The method of estimating reserves using the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) to generate a full range of possible outcomes and their associated probabilities of occurrence.

“prospect” A property on which indications of oil or gas have been identified based on available seismic and geological information.

“proved developed reserves” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

“proved reserves” Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following:

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“proved undeveloped reserves” or “PUDs” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.  Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

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“recompletion” An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

“reserves” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“resource play” An expansive contiguous geographical area with known accumulations of crude oil or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.

“royalty” The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil or natural gas produced and sold, unencumbered by expenses relating to the drilling, completing or operating of the affected well.

“royalty interest” An interest in an oil or natural gas property entitling the owner to shares of the crude oil or natural gas production free of costs of exploration, development and production operations.

“SEC” The United States Securities and Exchange Commission.

“standardized measure of discounted future net cash flows” or “Standardized Measure” The discounted future net cash flows relating to proved reserves based on the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period (unless prices are defined by contractual arrangements, excluding escalations based upon future conditions); current costs and statutory tax rates (to the extent applicable); and a 10% annual discount rate.

“three-way collar” A combination of options: a sold call, a purchased put and a sold put.  The sold call establishes a maximum price (ceiling) to be received for the volumes under contract.  The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.  

“working interest” The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all associated risks.

“workover” Operations on a producing well to restore or increase production.

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PART I

Item 1.       Business

Overview

We are an independent oil and gas company engaged in development, production, acquisition and exploration activities primarily in the Rocky Mountains region of the United States.  We were incorporated in the state of Delaware in 2003 in connection with our initial public offering.

Since our inception, we have built a strong asset base through a combination of property acquisitions, development of proved reserves and exploration activities.  Our current operations and capital programs are focused on organic drilling opportunities and on the development of previously acquired properties, specifically on projects that we believe provide the greatest potential for repeatable success and production growth, while selectively pursuing acquisitions that complement our existing core properties, such as the acquisition discussed below under “Acquisitions and Divestitures,” and exploring other basins where we can apply our existing knowledge and expertise to build production and add proved reserves.  As a result of lower crude oil prices during 2017 and 2018, we significantly reduced our level of capital spending and focused our drilling activity on projects that provide the highest rate of return, while closely aligning our capital spending with cash flows generated from operations.  During 2019, we focused on developing our large resource play in the Williston Basin of North Dakota and Montana, while continuing to closely align our capital spending with cash flows generated from operations.  We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own, such as the asset sales discussed below under “Acquisitions and Divestitures.”

As of December 31, 2019, our estimated proved reserves totaled 485.4 MMBOE and our 2019 average daily production was 125.5 MBOE/d, which results in an average reserve life of approximately 10.6 years.

The following table summarizes by core area, our estimated proved reserves as of December 31, 2019 with the corresponding pre-tax PV10% values, our fourth quarter 2019 average daily production rates, and our total standardized measure of discounted future net cash flows as of December 31, 2019:

During 2019, we incurred $778 million in exploration and development (“E&D”) expenditures, including $772 million for the drilling and completion of 210 gross (94.0 net) wells.  

Our current 2020 E&D budget is a range of $585 million to $620 million, which we expect to fund substantially with net cash provided by our operating activities and cash on hand.  To the extent net cash provided by operating activities is higher or lower than currently anticipated, we would generate more or less free cash flow than we currently anticipate, adjust our E&D budget accordingly, enter into agreements with industry partners, divest certain oil and gas property interests, adjust borrowings outstanding under our credit facility or access the capital markets as necessary.

Acquisitions and Divestitures

2019 Acquisitions and Divestitures.  In July 2019, we completed the divestiture of our interests in 137 non-operated, producing oil and gas wells located in McKenzie, Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $27 million (before closing adjustments).  

In August 2019, we completed the divestiture of our interests in 58 non-operated, producing oil and gas wells located in Richland County, Montana and Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $26 million (before closing adjustments).

On a combined basis, the divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2018 and our April 2019 average daily production.

There were no significant acquisitions during the year ended December 31, 2019.

2018 Acquisitions and Divestitures.  In July 2018, we completed the acquisition of approximately 54,800 net acres in the Williston Basin, including interests in 117 producing oil and gas wells and undeveloped acreage located in Richland County, Montana and McKenzie County, North Dakota for an aggregate purchase price of $130 million (before closing adjustments).  The producing properties had estimated proved reserves of 25.7 MMBOE as of the acquisition date, 84% of which were crude oil and NGLs.

There were no significant divestitures during the year ended December 31, 2018.

Subsequent to December 31, 2019, we completed the divestiture of our interests in 30 non-operated, producing oil and gas wells and related undeveloped acreage located in McKenzie County, North Dakota for aggregate sales proceeds of $25 million (before closing adjustments).  The divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2019 and 1% of our average daily production for the year ended December 31, 2019.  

Business Strategy

Our goal is to generate meaningful growth in shareholder value through the development, acquisition and exploration of oil and gas projects with attractive rates of return on capital.  Specifically, we have focused, and plan to continue to focus, on the following:

Efficiently Developing Existing Properties.  The development of our large resource play at our Williston Basin project in North Dakota and Montana continues to be our central objective.  We have assembled approximately 756,800 gross (476,300 net) developed and undeveloped acres in this area, on which we had four drilling rigs operating as of December 31, 2019.  During 2019, we completed and

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brought on production 133 gross (87 net) operated Bakken and Three Forks wells in the Williston Basin.  Under our current 2020 capital program, we expect to put on production approximately 122 gross wells in this area during the year.

At our Redtail field in the Denver-Julesburg Basin (the “DJ Basin”) in Weld County, Colorado, we have assembled approximately 96,400 gross (84,600 net) developed and undeveloped acres.  We completed 22 drilled uncompleted wells (“DUCs”) in our Redtail field during the first half of 2018, and no additional wells were drilled or completed in 2019.  During 2019 we worked on maintaining base production with improved artificial lift techniques and reductions in lease operating expenses.

Disciplined Financial Approach.  Our goal is to remain financially strong, yet flexible, through the prudent management of our balance sheet and active management of our exposure to commodity price volatility.  We have historically funded our acquisition and growth activity through a combination of internally generated cash flows, equity and debt issuances, bank borrowings and certain oil and gas property divestitures, as appropriate, to maintain our financial position.  As a result of lower crude oil prices during 2017 and 2018, we significantly reduced our level of capital spending and focused our drilling activity on projects that provide the highest rate of return, while closely aligning our capital spending with cash flows generated from operations.  During 2019, we focused on developing our large resource play in the Williston Basin of North Dakota and Montana, while continuing to closely align our capital spending with cash flows generated from operations.  From time to time, we monetize non-core properties and use the net proceeds from these asset sales to repay debt under our credit agreement or fund our E&D expenditures.  For example, during 2019 we sold certain oil and gas properties operated by third parties that no longer matched the profile of properties we desire to own.  In addition, to support cash flow generation on our existing properties and help ensure expected cash flows from newly acquired properties, we periodically enter into derivative contracts.  Typically, we use costless collars and swaps to provide an attractive base commodity price level.  

Growing Through Accretive Acquisitions.  Since 2010, we have completed 7 separate significant acquisitions of producing properties for total estimated proved reserves of 240.2 MMBOE, as of the effective dates of the acquisitions.  Our experienced team of management, business development, land, engineering and geoscience professionals has developed and refined an acquisition program designed to increase reserves and complement our existing properties, including identifying and evaluating acquisition opportunities, closing purchases and effectively managing the properties we acquire.  We intend to selectively pursue the acquisition of properties that are complementary to our core operating areas, as well as explore opportunities in other basins where we can apply our existing knowledge and expertise to build production and add proved reserves.

Competitive Strengths

We believe that our key competitive strengths lie in our focused asset portfolio, our experienced management and technical teams and our commitment to the effective application of new technologies.

Focused, Long-Lived Asset Base.  As of December 31, 2019, we had interests in 5,021 gross (2,171 net) productive wells on approximately 824,200 gross (523,600 net) developed acres across our geographical areas.  We believe the concentration of our operated assets presents us with multiple opportunities to successfully execute our business strategy by enabling us to leverage our technical expertise and take advantage of operational efficiencies.  Our proved reserve life is approximately 10.6 years based on year-end 2019 proved reserves and 2019 production.

Experienced Management and Technical Teams.  Our management team averages 23 years of experience in the oil and gas industry.  Our personnel have extensive experience in each of our core geographical areas and in all of our operational disciplines.  In addition, our team of acquisition professionals has an average of 20 years of experience in the evaluation, acquisition and operational assimilation of oil and gas properties.

Commitment to Technology.  In each of our core operating areas, we have accumulated extensive engineering, operational, geologic and geophysical technical knowledge.  Our technical team has access to an abundance of digital well log, seismic, completion, production and other subsurface information, which is analyzed in order to accurately and efficiently characterize the anticipated performance of our oil and gas reservoirs.  In addition, our information systems enable us to update our production databases through field automation.  This commitment to technology has increased the productivity and efficiency of our field operations and development activities.

We continue to advance our completion techniques by utilizing customized, right-sized completion designs based on calibrated models for each of our prospect areas, using multivariate analysis to understand which completion factors most significantly impact the results in each area, and piloting and adopting the latest completion technologies available.  Such customized designs utilize the optimum volume of proppant, diversion techniques, fluids and frac stages, allowing us to increase well performance while reducing cost.  We

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have increased stages pumped per day by focusing on new technologies such as quick-install wellhead connections and frac plug innovations.  We plan to continue to use right-sized completion designs on wells we drill in 2020, while also utilizing state-of-the-art drilling rigs, high-torque mud motors and evolving 3-D bit cutter technology to reduce time-on-location and total well cost.

Proved Reserves

Our estimated proved reserves as of December 31, 2019 are summarized by core area in the table below.  Refer to “Reserves” in Item 2 of this Annual Report on Form 10-K for information relating to the uncertainties surrounding these reserve categories.

Marketing and Major Customers

We principally sell our oil and gas production to end users, marketers and other purchasers that have access to nearby pipeline or rail takeaway.  In areas where there is no practical access to gathering pipelines, oil is trucked or transported to terminals, market hubs, refineries or storage facilities.  The tables below present percentages by purchaser that accounted for 10% or more of our total oil, NGL and natural gas sales for the years ended December 31, 2019, 2018 and 2017.  We believe that the loss of any individual purchaser

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would not have a long-term material adverse impact on our financial position or results of operations, as alternative customers and markets for the sale of our products are readily available in the areas in which we operate.

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Title to Properties

Our properties are subject to customary royalty interests, liens securing indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions.  Our credit agreement is also collateralized by a first lien on substantially all of our assets.  We do not believe that any of these burdens materially interfere with the use of our properties or the operation of our business.

We believe that we have satisfactory rights or title to all of our producing properties.  As is customary in the oil and gas industry, limited investigation of title is made at the time of acquisition of undeveloped properties.  In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.

Competition

The oil and gas industry is a highly competitive environment for acquiring properties, obtaining investment capital, securing oil field goods and services, marketing oil and natural gas products and attracting and retaining qualified personnel.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate.  Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our resources permit.  In addition, the unavailability or high cost of drilling rigs or other equipment and services could delay or adversely affect our development and exploration operations.  Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to obtain necessary capital as well as evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.  The price and availability of alternative energy sources, such as wind, solar, nuclear and electric power, could adversely affect our revenue.

Regulation

Regulation of Production

The production of oil and gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.  Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and periodic report submittals during operations.  All of the states in which we own and operate properties 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 oil and gas wells, the regulation of well spacing and the plugging and abandonment of wells.  The effect of these regulations is to limit the amount of oil and gas that we can produce from our wells and to limit the number of wells or the locations that we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing.  Moreover, each state generally imposes a production or severance tax with respect to the production or sale of oil, NGLs and natural gas within its jurisdiction.

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Currently, none of our production volumes are produced from offshore leases, however, some of our prior offshore operations were conducted on federal leases that are administered by the Bureau of Ocean Energy Management (the “BOEM”).  Among other things, BOEM regulations establish construction requirements for production facilities located on our federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases.  The present value of our future abandonment obligations associated with offshore properties was $41 million as of December 31, 2019.  We are therefore required to comply with the regulations and orders issued by the BOEM under the Outer Continental Shelf Lands Act.  

The Bureau of Land Management (“BLM”) establishes the basis for onshore royalty payments due under federal oil and gas leases through regulations issued under applicable statutory authority.  State regulatory authorities establish similar standards for royalty payments due under state oil and gas leases.  The basis for royalty payments established by the BLM and the state regulatory authorities is generally applicable to all federal and state oil and gas lessees.  Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

Regulation of Sale and Transportation of Oil

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices, however, Congress could reenact price controls or enact other legislation in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation.  The transportation of oil in common carrier pipelines is also subject to rate regulation.  The Federal Energy Regulatory Commission (the “FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act.  In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.  Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for crude oil transportation rates that allowed for an increase or decrease in the cost of transporting oil to the purchaser.  The FERC’s regulations include a methodology for oil pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates.  The most recent mandatory five-year review period resulted in a 2015 order from the FERC for the index to be based on Producer Price Index for Finished Goods (the “PPI-FG”) plus a 1.23% adjustment for the five-year period from July 1, 2016 through June 30, 2021.  This represents a decrease from the PPI-FG plus 2.65% adjustment from the prior five-year period.  The FERC determined that it would now use a calculation based on what it determined to be a superior data source, reflecting actual cost-of-service data as opposed to the accounting data historically used as a proxy for such information under the prior index methodology.  The regulations provide that each year the Commission will publish the oil pipeline index after the PPI-FG becomes available.  Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.  The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state.  Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis.  Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates.  When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs.  In addition, the FERC has emergency authority under the Interstate Commerce Act to intervene and direct priority use of oil pipeline transportation capacity, and the FERC exercised this authority over a specific pipeline in February 2014 in response to significant disruptions in the supply of propane.  Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Transportation and safety of oil and hazardous liquid is subject to regulation by the Department of Transportation (the “DOT”) under the Pipeline Integrity, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2012.  The Pipeline and Hazardous Material Safety Administration (“PHMSA”), an agency within the DOT, enforces regulations on all interstate liquids transportation and some intrastate liquids transportation.  The effect of regulatory changes under the DOT and their effect on interstate and intrastate oil and hazardous liquid transportation will not affect our operations in any way that is of material difference from those of our competitors.

A portion of our crude oil production may be shipped to market centers using rail transportation facilities owned and operated by third parties.  The DOT, generally, and PHMSA, more specifically, establish safety regulations relating to crude-by-rail transportation.  In addition, third-party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the DOT, the Federal

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Railroad Administration (the “FRA”) of the DOT, the Occupational Safety and Health Administration and other federal regulatory agencies.  

In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of 2008, which implemented regulations governing different areas related to railroad safety.  In response to train derailments occurring in the United States and Canada in 2013 and 2014, U.S. regulators have taken a number of additional actions to address the safety risks of transporting crude oil by rail.

In February 2014, the DOT issued an emergency order requiring all persons to ensure crude oil is properly tested and classed prior to offering such product into transportation, and to assure all shipments by rail of crude oil be handled as a Packing Group I or II hazardous material.  Also in February 2014, the Association of American Railroads entered into a voluntary agreement with the DOT to implement certain restrictions around the movement of crude oil by rail.  In May 2014 (and extended indefinitely in May 2015), the DOT issued an Emergency Restriction/Prohibition Order requiring each railroad carrier operating trains transporting 1,000,000 gallons or more of Bakken crude oil to provide notice to state officials regarding the expected movement of the trains through the counties in each state.  The PHMSA and FRA have also issued safety advisories and alerts regarding oil transportation and have issued a report focused on the increased volatility and flammability of Bakken crude oil as compared with other crudes in the U.S.  In May 2015, PHMSA issued new rules applicable to “high-hazard flammable trains,” defined as a continuous block of 20 or more tank cars loaded with a flammable liquid or 35 or more tank cars loaded with a flammable liquid dispersed throughout a train.  Among other requirements, the new rules require enhanced standards for newly constructed tank cars and retrofitting of existing tank cars, restricted operating speeds, a documented testing and sampling program, and routine assessments that evaluate certain safety and security factors.  In December 2015, the Fixing America’s Surface Transportation (“FAST”) Act became law, further extending PHMSA’s authority to improve the safety of transporting flammable liquids by rail and pursuant to which new regulations phasing out the use of certain older rail cars were finalized in August 2016.  In June 2016, the Protecting our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act became law.  The PIPES Act strengthens PHMSA’s safety authority, including an expansion of its ability to issue emergency orders, which was adopted by rule in October 2016 and further enhanced by rule in October 2019.  PHMSA continues to review further potential new safety regulations under the PIPES Act and the FAST Act.

We do not currently own or operate rail transportation facilities or rail cars.  However, the adoption of any regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the U.S., the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.  The effect of any such regulatory changes will not affect our operations in any way that is of material difference from those of our competitors.

Regulation of Transportation, Storage, Sale and Gathering of Natural Gas

The FERC regulates the transportation and, to a lesser extent, the sale of natural gas for resale in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 and regulations issued under those Acts.  In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas, effective January 1, 1993.  While sales by producers of natural gas can currently be made at unregulated market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business.

Our natural gas sales are affected by the availability, terms and cost of transportation.  The price and terms of access to pipeline transportation and underground storage are subject to extensive federal and state regulation.  From 1985 to the present, several major regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production, transportation and sales.  In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry that remain subject to the FERC’s jurisdiction, most notably interstate natural gas transmission companies and certain underground storage facilities.  These initiatives may also affect the intrastate transportation of natural gas under certain circumstances.  The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in the markets in which our natural gas is sold.  Regulations implemented by the FERC could result in an increase in the cost of transportation service on certain petroleum product pipelines.  In addition, the natural gas industry has historically been heavily regulated.  Therefore, we cannot provide

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any assurance that the less stringent regulatory approach established by the FERC 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.

Transportation and safety of natural gas is subject to regulation by the DOT under the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2012.  In addition, intrastate natural gas transportation is subject to enforcement by state regulatory agencies and PHMSA enforces regulations on interstate natural gas transportation.  State regulatory agencies can also create their own transportation and safety regulations as long as they meet PHMSA’s minimum requirements.  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 of the 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.  Likewise, the effect of regulatory changes by the DOT and their effect on interstate natural gas transportation will not affect our operations in any way that is of material difference from those of our competitors.

The failure to comply with these rules and regulations can result in substantial penalties.  We use the latest tools and technologies to remain compliant with current pipeline safety regulations.

In October 2015, a failure at an underground natural gas storage facility in Southern California prompted PHMSA to issue an advisory bulletin reminding owners and operators of underground storage facilities to review operations, identify the potential for facility leaks and failures and to review and update emergency plans.  The State of California proclaimed the underground natural gas storage facility an emergency situation in January 2016.  A federal task force was also convened to make recommendations to help avoid such failures.  An interim final rule of PHMSA became effective in January 2017 which adopted certain specific industry recommended practices into Part 192 of the Federal Pipeline Safety Regulations.  PHMSA later reopened the post-promulgation comment period through November 2017 in response to petitions for reconsideration and has stated it would consider such comments further when it adopts a final rule.  Under the interim final rule, if an operator fails to take any measures recommended it would need to justify in its written procedures why the measure is impracticable and unnecessary.  PHMSA regulations had previously covered much of the surface piping up to the wellhead at underground natural gas storage facilities served by pipelines and did not extend in part to the “downhole” portion of these facilities.  The adopted requirements cover design, construction, material, testing, commissioning, reservoir monitoring and recordkeeping for existing and newly constructed underground natural gas storage facilities as well as procedures and practices for newly constructed and existing underground natural gas storage facilities, such as operations, maintenance, threat identification, monitoring, assessment, site security, emergency response and preparedness, training, recordkeeping and reporting.  These regulations and any further increased attention to and requirements for underground storage safety and infrastructure by state and federal regulators that may result from this incident will not affect us in a way that materially differs from the way it affects other natural gas producers.

Environmental Regulations

General.  Our oil and gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge or release of materials into the environment or otherwise relating to environmental protection.  Numerous governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations to implement and enforce such laws, which often require costly compliance measures that carry substantial penalties for noncompliance.  These laws and regulations may require the acquisition of a permit before drilling or facility construction commences; restrict the types, quantities and concentrations of various materials that can be released into the environment; limit or prohibit project siting, construction or drilling activities on certain lands; require remedial and closure activities to prevent pollution from former operations; and impose substantial liabilities for unauthorized pollution.  The EPA and analogous state agencies may delay or refuse the issuance of required permits or otherwise include onerous or limiting permit conditions that may have a significant adverse impact on our ability to conduct operations.  

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly material handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as those of the oil and gas industry in general.  While we believe that we are in compliance, in all material respects, with current applicable environmental laws and regulations, future environmental enforcement remains a material risk due to the potential magnitude of exposure in the event of a noncompliance.  We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance.  Such expenditures are included within our overall capital budget and are not separately itemized.

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The environmental laws and regulations which have the most significant impact on the oil and gas exploration and production industry are as follows:

Superfund.  The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA” or “Superfund”), and comparable state laws impose strict joint and several liability for sites contaminated by certain hazardous substances on classes of potentially responsible persons.  These persons include the owner or operator of the site where a release occurred and anyone who disposed of or arranged for the disposal of the hazardous substance released at the site.  Under CERCLA, such persons may be subject to joint and several 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.  In the course of our ordinary operations, we may use, generate or handle material that may be regulated as “hazardous substances.”  Consequently, we may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites where these materials have been disposed or released.

We currently own or lease, and in the past have owned or leased, properties that for many years have been used for the exploration and production of oil and gas.  Although we have used operating and disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on, under or from the properties owned or leased by us or on, under or from other locations where such substances have been taken for recycling or disposal.  In addition, many of these owned and leased properties have been previously owned or operated by third parties whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under our control and not known to us.  Similarly, the disposal facilities where discarded materials are sent are also often operated by third parties whose waste treatment and disposal practices are similarly not under our control.  While we only use what we consider to be reputable disposal facilities, we might not know of a potential problem if the problem itself is not discovered until years later.  Current and formerly owned or operated properties, adjacent affected properties, offsite disposal facilities and substances disposed or released on them may be subject to CERCLA and analogous state laws.  Under these laws, we could be required:

At this time, we do not believe that we are a potentially responsible party with respect to any Superfund site and we have not been notified of any claim, liability or damages under CERCLA or any state analog.

Oil Pollution Act.  The Oil Pollution Act of 1990 (“OPA”) and regulations issued under OPA impose strict, joint and several liability on “responsible parties” for removal costs and damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States.  A “responsible party” includes the owner or operator of an onshore facility and the lessee, permittee or holder of a right of use and easement of the area in which an offshore facility is located.  OPA establishes a liability limit for onshore facilities of $350 million per spill, while the liability limit for offshore facilities is the payment of all removal costs plus $75 million per spill damages.  These limits do not apply if the spill is caused by a responsible party’s gross negligence or willful misconduct; the spill resulted from a responsible party’s violation of a federal safety, construction or operating regulation; a responsible party fails to report a spill or to cooperate fully in a cleanup; or a responsible party fails to comply with an order issued under the authority of the Intervention on the High Seas Act.  OPA requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35 million to cover liabilities related to an oil spill for which such responsible party is statutorily responsible.  The President of the United States may increase the amount of financial responsibility required under OPA by up to $150 million, depending on the risk represented by the quantity or quality of oil that is handled by the facility.  Any failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to administrative penalties.  We believe we are in compliance with all applicable OPA financial responsibility obligations.  Moreover, we are not aware of any action or event that would subject us to liability under OPA.

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Resource Conservation and Recovery Act.  The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.  Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements.  Additionally, various federal, state and local agencies have jurisdiction over transportation, storage and disposal of hazardous waste and seek to regulate movement of hazardous waste in ways not preempted by federal law.  We generate solid and hazardous wastes that are subject to RCRA and comparable state laws.  Drilling fluid, produced water and many other wastes associated with the exploration, development and production of crude oil or natural gas are currently exempt from RCRA’s hazardous waste provisions.  However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be regulated as hazardous waste in the future.  In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting it to reconsider the RCRA hazardous waste exemption for exploration, production and development wastes.  In December 2016, the court entered a Consent Decree resolving the litigation, under which the EPA would issue such a rulemaking or make a determination that it was not necessary by March 15, 2019.  In response, in April 2019, the EPA issued a determination that rulemaking to address waste from oil and gas exploration and production operations was not necessary at this time.  However, it is possible that the EPA will take up such regulatory changes at a later date.  Any such change in the current RCRA exemption and comparable state laws could result in an increase in the costs to manage and dispose of wastes.  Additionally, these exploration and production wastes will continue to be regulated by state agencies as solid waste.  Also, non-exempt waste streams generated by us will continue to be subject to existing onerous hazardous waste regulations.  Although we do not believe the current costs of managing our wastes (as they are presently classified) to be significant, any repeal or modification of the oil and gas exploration and production exemption by administrative, legislative or judicial process, or modification of similar exemptions in analogous state statutes would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.

Clean Water Act.  The Federal Water Pollution Control Act, or the Clean Water Act, as amended (“CWA”), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state waters or other 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 an analogous state agency.  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, CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

Where required, costs may be associated with the treatment of wastewater and/or the development and implementation of storm water pollution prevention plans.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of CWA and analogous state laws and regulations.  

In addition, the CWA requires permits for discharges of dredged or filled materials into waters of the United States.  These permits (“404 Permits”) are under the joint jurisdiction of the EPA and the Army Corps of Engineers.  404 Permits may be required where development or construction activities have the potential to impact wetland areas that are considered waters of the United States.  In 2015, the EPA greatly expanded the definition of waters of the United States.  In doing so, it required 404 permits for disturbances in areas before not considered subject to United States CWA jurisdiction.  However, effective December 23, 2019, the rule broadening the definition was repealed, ostensibly restoring jurisdiction to only those waterbodies (including wetlands) that have a “significant nexus” to navigable waters of the United States.  Further rulemaking to refine the definition of waters of the United States is expected from the EPA in 2020.  Any expansion of the scope of the CWA could increase costs associated with permitting and regulatory compliance.  However, it is expected that any such change would not disparately affect us and our competitors.

Air Emissions.  The Federal Clean Air Act, as amended (the “CAA”), and comparable state laws regulate emissions of various air pollutants from various industrial sources through air emissions permitting programs and also impose other monitoring and reporting requirements.  New Source Performance Standards were promulgated for the oil and gas industry in 2012.  These standards set limits for sulfur dioxide and volatile organic compound emissions and required application of reduced emission completion techniques by the industry.  We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining pre-construction and operating permits and approvals for air emissions.  In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.  Federal and state regulatory agencies can impose penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

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In May 2016, the EPA issued a final rule regulating methane emissions from oil and natural gas operations (the “Subpart OOOOa Rule”).  This rule applies to emissions from new, reconstructed and modified processes and equipment and also requires owners and operators to find and repair leaks to address fugitive emissions.

Certain states have also adopted, or are considering, regulations addressing methane releases from oil and gas operations.  Colorado has adopted regulations reducing methane emissions from oil and gas operations.  Compliance with rules applicable to jurisdictions in which we operate could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.  

However, in September 2019, the EPA proposed two alternative amendments to the Subpart OOOOa Rule.  Both amendments would remove all methane-specific requirements from production and processing segments.  The first amendment would also remove transportation and storage facilities from the definition of covered facilities.  The comment period for the proposed rule closed on November 25, 2019.  The net effect of either of these amendments, if finalized, would significantly reduce compliance obligations and associated costs.

Hydraulic Fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations.  The process involves the injection of mainly water and sand plus a de minimis amount of chemicals under pressure into formations to fracture the surrounding rock and stimulate production.  We expect that we will utilize hydraulic fracturing for the foreseeable future to complete or recomplete wells in areas in which we work.  Hydraulic fracturing is typically regulated at the state level; however, the EPA issued guidance in 2014 to address hydraulic fracturing injections using diesel.

In addition, in June 2016, the EPA issued a final rule promulgating pretreatment standards for discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works.  The EPA, along with other federal agencies such as the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S. Department of Interior and the White House Council for Environmental Quality continue to study various aspects of hydraulic fracturing.  

In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.  Multiple states, including Texas, Colorado and Wyoming have already adopted rules requiring disclosures of chemicals used in hydraulic fracturing and others have enacted regulations imposing additional requirements on activities involving hydraulic fracturing.  Chemical disclosure regulations may increase compliance costs and may limit our ability to use cutting-edge technology in markets where disclosure is required.  Further, laws such as those restricting the use of or regulating the time, place and manner of hydraulic fracturing (such as setback ordinances) may impact our ability to fully extract reserves.  No assurance can be given as to whether or not such measures might be adopted in the jurisdictions in which our properties are located.  If new laws, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where our properties are located, such legal requirements could prohibit or make it more difficult or costly for us to perform hydraulic fracturing activities.

Further, in May 2014, the EPA published an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act, relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production.  On July 11, 2014, the EPA extended the public comment period for the rulemaking to September 18, 2014.  The EPA has not yet taken further action with respect to this rule.  Depending on the precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary information, and failure to do so may subject us to penalties.  In addition, we may be required to disclose information of third parties, that may be inaccurate or that we may be contractually prohibited from disclosing, which could also subject us to penalties.

In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008.  This study, as well as subsequent studies and reports, may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells.  If such new laws or rules are adopted, our operations may be curtailed while alternative treatment and disposal methods are developed and approved.

Global Warming and Climate Change.  In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes.  Based on these findings, the EPA has adopted and implemented regulations that restrict emissions of GHG under existing provisions of the CAA.

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At present, the EPA may establish GHG permitting requirements for stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) and Title V requirements of the CAA.  Certain of our equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs.  For any equipment or installation so subject, we may have to incur increased compliance costs to capture related GHG emissions.

In October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements.  The public comment period for the rulemaking concluded on December 16, 2016.  However, although the rulemaking remains on the EPA’s long-term regulatory agenda, no final rule has been published.  

In August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units.  The rule, commonly called the “Clean Power Plan”, required states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030.  However, in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it was being challenged in court.  On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan and on August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the Clean Power Plan.  The EPA issued the final ACE rule in June 2019.  As expected, over 20 states and public health and environmental organizations have challenged the rule.  The EPA has sought expedited review in the hopes that the cases will be resolved by the summer of 2020.  If the ACE rule were to become final, the costs of compliance are expected to be significantly less than they would have been under the Clean Power Plan.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, GHG permitting and/or regional GHG “cap and trade” programs.  Most of these “cap and trade” programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.  Also, in recent years, lawsuits have been brought against other energy companies for matters relating to climate change.  Multiple states and localities have also initiated investigations in climate-change related matters.  While the current suits focus on a variety of issues, at their core they seek compensation for the effects of climate change from companies with ties to GHG emissions.  It is currently unknown what the outcome of these types of actions may be, but the costs of defending against such actions may be expected to rise.  Finally, it should be noted that many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our assets and operations.

Consideration of Environmental Issues in Connection with Governmental Approvals.  Our operations frequently require licenses, permits and/or other governmental approvals.  Several federal statutes, including the Outer Continental Shelf Lands Act (“OCSLA”), the National Environmental Policy Act (“NEPA”) and the Coastal Zone Management Act (“CZMA”), require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions.  OCSLA, for instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment.  Similarly, NEPA requires the U.S. Department of Interior and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment.  In the course of such evaluations, an agency would have to prepare an environmental assessment and potentially an environmental impact statement.  Recent federal court cases involving natural gas pipelines have involved challenges to the sufficiency of the evaluation of climate change impacts in environmental impact statements prepared under NEPA.  The CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and gas development.  In obtaining various approvals from the U.S. Department of Interior, we must certify that we will conduct our activities in a manner consistent with all applicable regulations.

Employees

As of January 31, 2020, we had approximately 505 full-time employees.  Our employees are not represented by any labor unions.  We consider our relations with our employees to be satisfactory and have never experienced a work stoppage or strike.

​

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Available Information

We maintain a website at the address www.whiting.com.  We are not including the information contained on our website as part of, or incorporating it by reference into, this report.  We make available free of charge (other than an investor’s own Internet access charges) through our website our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, including exhibits and amendments to these reports, as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC.

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Item 1A.      Risk Factors

Each of the risks described below should be carefully considered, together with all of the other information contained in this Annual Report on Form 10-K, before making an investment decision with respect to our securities.  In the event of the occurrence, reoccurrence, continuation or increased severity of any of the risks described below, our business, financial condition or results of operations could be materially and adversely affected, and you may lose all or part of your investment.

Oil and natural gas prices are very volatile.  An extended period of low oil and natural gas prices may adversely affect our business, financial condition, results of operations or cash flows.

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices.  The price we receive for our oil, NGL and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to, the following:

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These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements.  Also, prices for crude oil and prices for natural gas do not necessarily move in tandem.  Declines in oil or natural gas prices would not only reduce revenue, but could also reduce the amount of oil and natural gas that we can economically produce and therefore potentially lower our oil and gas reserve quantities.  If the oil and natural gas industry experiences extended periods of low prices, we may, among other things, be unable to meet all of our financial obligations or make planned expenditures.

Substantial and extended declines in oil, NGL and natural gas prices have resulted and may continue to result in impairments of our proved oil and gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures.  To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending, sell assets or borrow to fund any such shortfall.  Lower commodity prices may reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of our lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations described in the credit agreement.  Upon a redetermination, if total outstanding credit exposure exceeds the redetermined borrowing base, we will be required to prepay outstanding borrowings in an aggregate principal amount equal to such excess in six substantially equal monthly installments.

Lower commodity prices may also make it more difficult for us to comply with the covenants and other restrictions in the agreements governing our debt as described under the risk factor entitled “The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.”

Alternatively, higher oil, NGL and natural gas prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives, which may in turn cause us to experience net losses.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition, results of operations or cash flows.

Our future success will depend on the success of our exploration, development and production activities.  Our oil and natural gas exploration and development activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production.  Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.  Refer to the risk factor entitled “Reserve estimates depend on many assumptions that may turn out to be inaccurate...” for a discussion of the uncertainty involved in these processes.  Our cost of drilling, completing and operating wells is often uncertain before drilling commences.  Overruns in budgeted expenditures are common risks that can make a particular project uneconomical.  Further, many factors may curtail, delay or cancel drilling, including, but not limited to, the following:

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Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations, cash flows and business prospects.

As of December 31, 2019, we had outstanding $262 million of 1.25% Convertible Senior Notes due April 2020 and $2.2 billion of senior notes, which consisted of $774 million of 5.75% Senior Notes due March 2021, $408 million of 6.25% Senior Notes due April 2023 and $1,000 million of 6.625% Senior Notes due January 2026.  We had $375 million of borrowings and $2 million in letters of credit outstanding under Whiting Oil and Gas Corporation’s (“Whiting Oil and Gas”) credit facility with $1.4 billion of available borrowing capacity.  The credit agreement matures on April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 1.25% Convertible Senior Notes due April 2020) have a maturity date prior to 91 days after April 12, 2023, the maturity date shall be the date that is 91 days prior to the maturity of such senior notes.  We are allowed to incur additional indebtedness, provided that we meet certain requirements in the indentures governing our senior notes and Whiting Oil and Gas’ credit agreement.

Our level of indebtedness and the covenants contained in the agreements governing our debt could have important consequences for our operations, including, but not limited to:

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances.  If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt.  Refer to the risk factor entitled “The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.”

If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

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Our earnings and cash flow could vary significantly from year to year due to the volatility of oil and natural gas prices.  As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods.  Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments.  A range of economic, competitive, business and industry factors will affect our future financial performance and, as a result, our ability to generate cash flow from operations and service our debt.  Factors that may cause us to generate cash flow that is insufficient to meet our debt obligations include the events and risks related to our business, many of which are beyond our control.  Any cash flow insufficiency would have a material adverse impact on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.  If we do not generate sufficient cash flow from operations to service our outstanding indebtedness, or if future borrowings are not available to us in an amount sufficient to enable us to pay or refinance our indebtedness, we may be required to undertake various alternative financing plans, which may include:

We cannot assure you that we would be able to implement any of the above alternative financing plans, if necessary, on commercially reasonable terms or at all.  If we cannot make scheduled payments on our indebtedness or otherwise fail to comply with the covenants and other restrictions in the agreements governing our debt, we will be in default and the lenders under Whiting Oil and Gas’ credit agreement and the holders of our senior notes and convertible senior notes could declare all outstanding principal and interest to be due and payable.  Additionally, the lenders under Whiting Oil and Gas’ credit agreement could terminate their commitments to loan money and could foreclose against our assets collateralizing our borrowings, and we could be forced into bankruptcy or liquidation.  If the amounts outstanding under any of our significant indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to the lenders or to our other debt holders.  Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms or at all, would materially and adversely affect our business, financial position, results of operations and cash flows.

A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital.

Certain segments of the investor community have developed negative sentiment towards investing in our industry.  Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices.  In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations.  Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects.

Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.  Refer to the Risk Factor entitled “Negative public perception regarding us and/or our industry could have an adverse effect on our operations.”

The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.

The indentures governing our senior notes and convertible senior notes and Whiting Oil and Gas’ credit agreement contain various restrictive covenants that may limit our management’s discretion in certain respects.  In particular, these agreements limit our and our subsidiaries’ ability to, among other things:

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In addition, Whiting Oil and Gas’ credit agreement requires us, as of the last day of any quarter, to maintain the following ratios (as defined in the credit agreement): (i) a consolidated current assets to consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 4.0 to 1.0.  If we were in violation of these covenants, then we may not be able to incur additional indebtedness, including under Whiting Oil and Gas’ credit agreement.  Also, the indentures under which we issued our senior notes restrict us from incurring additional indebtedness and making certain restricted payments, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1.0.  Factors that may adversely affect our ability to comply with these covenants include oil or natural gas price declines, lack of liquidity in property and capital markets and our inability to execute on our business plan.

If we fail to comply with the restrictions in the indentures governing our senior notes and convertible senior notes, Whiting Oil and Gas’ credit agreement or any other subsequent financing agreements, a default may allow the creditors to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies.  In addition, lenders may be able to terminate any commitments they had made to make further funds available to us.  Furthermore, if we were unable to repay the amounts due and payable under Whiting Oil and Gas’ credit agreement, those lenders could proceed against the collateral granted to them to secure that indebtedness.  In the event that our lenders or noteholders accelerate the repayment of our borrowings, we and our subsidiaries may not have sufficient assets or be able to borrow sufficient funds to repay or refinance that indebtedness.  Also, if we are in default under the agreements governing our indebtedness, we will not be able to pay dividends on our capital stock.

Moreover, the borrowing base limitation on Whiting Oil and Gas’ credit agreement is redetermined on May 1 and November 1 of each year, and may be the subject of special redeterminations described in such credit agreement based on an evaluation of our oil and gas reserves.  Because oil and gas prices are principal inputs into the valuation of our reserves, if oil and gas prices decline, our borrowing base could be reduced at the next redetermination date or during future redeterminations.  Upon a redetermination, if total outstanding credit exposure exceeds the redetermined borrowing base, we will be required to prepay outstanding borrowings in an aggregate principal amount equal to such excess in six substantially equal monthly installments.  We may not have sufficient funds to make such repayments.

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and a failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our business, financial condition, results of operations or cash flows.

Our future growth prospects are dependent upon our ability to identify optimal strategies for investing our capital resources to produce rates of return.  In developing our business plan, we consider allocating capital and other resources to various aspects of our business including well development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives.  We also consider our likely sources of capital, including cash generated from operations and borrowings under Whiting Oil and Gas’ credit

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agreement.  Notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions.  If we fail to identify optimal business strategies or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future growth may be adversely affected.  Moreover, economic or other circumstances may change from those contemplated by our business plan and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

A large portion of our producing properties are concentrated in the Williston Basin of North Dakota and Montana, making us vulnerable to risks associated with operating in one major geographic area.

A large portion of our producing properties are geographically concentrated in the Williston Basin of North Dakota and Montana.  At December 31, 2019, approximately 93% of our total estimated proved reserves were attributable to properties located in this area.  Because of this concentration in a limited geographic area, the success and profitability of our operations may be disproportionately exposed to regional factors compared to competitors having more geographically dispersed operations.  These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints, (ii) the availability of rigs, equipment, oilfield services, supplies and labor, (iii) the availability of processing and refining facilities and (iv) infrastructure capacity.  In addition, our operations in the Williston Basin may be adversely affected by severe weather events such as floods, blizzards, ice storms, tornadoes and freezing temperatures which can intensify competition for the items and services described above and may result in periodic shortages.  The concentration of our operations in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events (which may result in third-party lawsuits), industrial accidents, labor difficulties, civil disturbances, public protests or terrorist attacks.  Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration.  Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations and cash flows.  

If oil, NGL and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and gas properties.

Accounting rules require that we periodically review the carrying value of our producing oil and gas properties for possible impairment.  Based on specific market factors and circumstances at the time of prospective impairment reviews (which may include depressed oil, NGL and natural gas prices and the continuing evaluation of development plans, production data, economics, possible asset sales and other factors) we may be required to write down the carrying value of our oil and gas properties.  For example, we recorded an $835 million impairment charge during 2017 for the partial write-down of the Redtail field in Colorado.  A write-down constitutes a non-cash charge to earnings.  We may incur additional impairment charges in the future, which could have a material adverse effect on our business, financial condition, results of operations or cash flows in the period recognized.

We may continue to incur cash and noncash charges that would negatively impact our future results of operations and liquidity.

While executing our strategic priorities to reduce financial leverage and complexity and to lower our capital expenditures in the face of lower commodity prices, we have incurred certain cash charges.  As we continue to focus on our strategic priorities, we may incur additional cash and noncash charges in the future.  If incurred, these charges could have a material adverse effect on our liquidity and results of operations in the period recognized.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations.  The process involves the injection of mainly water and sand plus a de minimis amount of chemicals under pressure into formations to fracture the surrounding rock and stimulate production.  We expect that we will utilize hydraulic fracturing for the foreseeable future to complete or recomplete wells in the areas in which we work.  Hydraulic fracturing is typically regulated at the state level, however, the U.S. Environmental Protection Agency (the “EPA”) issued guidance in 2014 to address hydraulic fracturing injections involving diesel.  In addition, in June 2016, the EPA issued a final rule promulgating pretreatment standards for discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works.  The EPA,

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along with other federal agencies such as the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S. Department of Interior and the White House Council for Environmental Quality continue to study various aspects of hydraulic fracturing.

In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.  Multiple states, including Texas, Colorado and Wyoming have already adopted rules requiring disclosures of chemicals used in hydraulic fracturing and others have enacted regulations imposing additional requirements on activities involving hydraulic fracturing.  Chemical disclosure regulations may increase compliance costs and may limit our ability to use cutting-edge technology in markets where disclosure is required.  Further, laws such as those restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing (such as setback ordinances) may impact our ability to fully extract reserves.  No assurance can be given as to whether or not such measures might be considered or implemented in the jurisdictions in which our properties are located.  If new laws, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where our properties are located, such legal requirements could prohibit or make it more difficult or costly for us to perform hydraulic fracturing activities.

Further, in May 2014, the EPA published an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act, relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production.  On July 11, 2014, the EPA extended the public comment period for the rulemaking to September 18, 2014.  The EPA has not yet taken further action with respect to this rule.  Depending on the precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary information, and failure to do so may subject us to penalties.  In addition, we may be required to disclose information of third parties, which may be inaccurate or which we may be contractually prohibited from disclosing, which could also subject us to penalties.

In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008.  This study, as well as subsequent studies and reports, may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells.  If such new laws or rules are adopted, our operations may be curtailed while alternative treatment and disposal methods are developed and approved.

Refer to “Hydraulic Fracturing” in Item 2 of this Annual Report on Form 10-K for more information on hydraulic fracturing.

We have entered into physical delivery contracts and do not expect to be able to deliver all the oil required under such contracts and, as a result, we expect we will be required to make deficiency payments.

As of December 31, 2019, we had three physical delivery contracts which require us to deliver fixed volumes of crude oil.  One of these contracts is tied to oil production at our Sanish field in Mountrail County, North Dakota, the second is tied to oil production in the Williston Basin and the third is tied to oil production at our Redtail field in Weld County, Colorado.  Although we believe that our production and reserves are sufficient to fulfill the delivery commitments at our Sanish field in North Dakota and the Williston Basin, if we fail to deliver the committed volumes, we would be required to pay deficiency payments of $7.00 and $5.75, respectively, per undelivered barrel (subject to upward adjustment).  At our Redtail field, we have determined that it is not probable that future oil production will be sufficient to meet the minimum volume requirements under the contract in this area.  We expect to make periodic deficiency payments under the Redtail contract that currently total $5.24 per undelivered Bbl through the April 2020 termination date.  During 2019, 2018 and 2017, total deficiency payments under this contract amounted to $64 million, $37 million and $42 million, respectively.  Refer to “Properties – Delivery Commitments” for more information about these delivery contracts.

Reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors.  Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves referred to in this Annual Report on Form 10-K.

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In order to prepare our estimates, we must project production rates and timing of development expenditures.  We must also analyze available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary.  The process also requires economic assumptions about matters such as the following, among others:

Therefore, estimates of oil and natural gas reserves are inherently imprecise.  Actual future production, oil, NGL and natural gas prices, revenues, taxes, exploration and development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of reserves referred to in this Annual Report on Form 10-K.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved reserves, as referred to in this report, is the current market value of our estimated proved oil and natural gas reserves.  In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on 12-month average prices and current costs as of the date of the estimate.  The 12-month average prices used for the year ended December 31, 2019 were $55.69 per Bbl of oil and $2.58 per MMBtu of natural gas.  Actual future prices and costs may differ materially from those used in the estimate.  If the 12-month average oil prices used to calculate our oil reserves decline by $1.00 per Bbl, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2019 would have decreased by $137 million.  If the 12-month average natural gas prices used to calculate our natural gas reserves decline by $0.10 per MMBtu, then the standardized measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2019 would have decreased by $41 million.

Our exploration and development operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and gas industry is capital intensive.  We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of oil and natural gas reserves.  To date, we have financed capital expenditures through a combination of internally generated cash flows, equity and debt issuances, bank borrowings, agreements with industry partners and oil and gas property divestments.  We intend to finance future capital expenditures substantially with cash flow from operations, cash on hand, borrowings under our credit agreement and proceeds from asset divestitures.  Our cash flow from operations and access to capital is subject to a number of variables, including, but not limited to:

If our revenues or the borrowing base under our credit agreement decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves, or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels.

We may, from time to time, need to seek additional financing.  There can be no assurance as to the availability or terms of any additional financing.  Disruptions in the capital and credit markets, particularly in the energy sector, could limit our ability to access these markets

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or may significantly increase our cost to borrow.  If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the inability to access the cash and credit markets to obtain additional financing, on favorable terms or otherwise, could result in a curtailment of our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, we may not be able to sustain production.

Unless we conduct successful exploration, development and production activities or acquire properties containing proved reserves, our proved reserves will decline over time.  Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors.  Our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and producing our current reserves and finding economically recoverable or acquiring additional economically recoverable reserves.  In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources to acquire attractive companies or properties.  Therefore, we may not be able to develop, find or acquire additional reserves to sustain or replace our current and future production, which could adversely affect our business, financial condition, results of operations or cash flows.

Our credit rating could negatively impact our availability and cost of capital and could require us to post more collateral under certain commercial arrangements.

Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, transportation, processing and hedging agreements.  These collateral requirements depend, in part, on our credit rating.  We may be requested or required by other counterparties to post additional collateral, which may be in the form of additional letters of credit, cash or other acceptable collateral.  Any downgrade to our credit ratings could impact the posting of collateral consisting of cash or letters of credit, which would reduce availability under our credit agreement and negatively impact our liquidity.

Market conditions or operational impediments may hinder our access to oil and gas markets or delay our production.

In connection with our continued development of oil and gas properties, we are exposed to the impact of delays or interruptions of production from wells on these properties, caused by transportation capacity constraints, curtailment of production or the interruption of transporting oil and gas volumes produced.  In addition, market conditions or a lack of satisfactory oil and gas transportation arrangements may hinder our access to oil and gas markets or delay our production.  The availability of a ready market for our oil, NGL and natural gas production depends on a number of factors, including the demand for and supply of oil, NGLs and natural gas, downstream market conditions and competing supply alternatives.  Our ability to market our production also depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties and the ability to obtain such services on acceptable terms.  We may be disproportionately exposed to the impact of delays or interruptions of production caused by market constraints or the interruption of transporting oil and gas produced.  This could lead to production curtailments or shut-ins, and reduced revenue which could materially harm our business.  We may enter into arrangements for transportation services and sales to reduce curtailment risks.  However, these services expose us to the risk that third parties will default on their obligations under such arrangements.  

Risks associated with the production, gathering, transportation and sale of oil, NGLs and natural gas could adversely affect net income and cash flows.

Our net income and cash flows will depend upon, among other things, oil, NGL and natural gas production and the prices received and costs incurred to develop and produce oil and natural gas reserves.  Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, NGLs and natural gas will decrease revenues and increase expenditures.  For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages.  Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing net income.  We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.  Also, our oil, NGL and natural gas production depends in large part on the proximity and capacity of pipeline systems and transportation facilities which are mostly owned by third parties.  The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans.  Similarly, curtailments or damage to pipelines and other transportation facilities used to transport oil, NGL and natural gas production to markets for sale could decrease revenues or increase transportation expenses.  Any such curtailments or damage to the gathering systems could also require finding

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alternative means to transport oil, NGL and natural gas production, which alternative means could result in additional costs that will have the effect of increasing transportation expenses.

Also, accidents involving rail cars could result in significant personal injuries and property and environmental damage.  In May 2015, the Pipeline and Hazardous Material Safety Administration issued new rules applicable to “high-hazard flammable trains”, discussed in “Item 1 Business – Regulation – Regulation of Sale and Transportation of Oil” above, which could increase transportation expenses.  Similarly, regulatory responses to the October 2015 failure at a Southern California underground natural gas storage facility could also lead to increased expenses for underground storage.

In addition, drilling, production and transportation of hydrocarbons bear the inherent risk of loss of containment.  Potential consequences include, but are not limited to, loss of reserves, loss of production, loss of economic value associated with the affected wellbore, personal injuries and death, contamination of air, soil, ground water and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.

Part of our business strategy includes selling properties which subjects us to various risks.

Part of our business strategy includes selling properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.  However, there is no assurance that such sales will occur in the time frames or with the economic terms we expect.  Unless we conduct successful exploration, development and production activities or acquire properties containing proved reserves, divestitures of our properties will reduce our proved reserves and potentially our production.  We may not be able to develop, find or acquire additional reserves sufficient to replace such reserves and production from any of the properties we sell.  Additionally, agreements pursuant to which we sell properties may include terms that survive closing of the sale, including but not limited to indemnification provisions, which could result in us retaining substantial liabilities.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production.  Failure to drill sufficient wells in order to hold acreage will result in substantial lease renewal costs, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established on our undeveloped acreage, the underlying leases will expire.  As of December 31, 2019, the portion of our net undeveloped acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 18% in 2020, 13% in 2021 and 15% in 2022.  The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all.  In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire.  As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations or cash flows.

The unavailability or cost of additional drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis or within our budget.

The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages.  Historically, there have been shortages of drilling rigs, completion crews and other oilfield equipment as demand for these items has increased along with the number of wells being drilled and completed.  These factors also cause significant increases in costs for equipment, services and personnel.  Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs and other oilfield goods and services.  Shortages of field personnel and other professionals, drilling rigs, completion crews, equipment or supplies or price increases could delay or adversely affect our exploration and development operations, which could restrict such operations or have a material adverse effect on our business, financial condition, results of operations or cash flows.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage.  These scheduled drilling locations represent a significant part of our growth strategy.  Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs of oil field

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goods and services, drilling results, our ability to extend drilling acreage leases beyond expiration, regulatory approvals and other factors.  Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or gas from these or any other potential drilling locations.  As such, our actual drilling activities may materially differ from those presently identified, which could in turn adversely affect our business, financial condition, results of operations or cash flows or require us to remove certain proved undeveloped reserves from our proved reserve base if we are unable to drill those PUD locations within the SEC’s 5-year window.

Weaker price differentials and/or weaker benchmark prices of oil and natural gas and the wellhead price we receive could have a material adverse effect on our business, financial condition, results of operations or cash flows.

The prices that we receive for our oil and natural gas production generally trade at a discount, but sometimes at a premium, to the relevant benchmark prices such as NYMEX.  A negative or positive difference between the benchmark price and the price received is called a differential.  The differential may vary significantly due to market conditions, the quality and location of production and other risk factors, as demonstrated in the fourth quarter of 2018 when our oil differentials weakened substantially.  We cannot accurately predict oil and natural gas differentials.  Changes in the differential and decreases in the benchmark price for oil and natural gas could have a material adverse effect on our business, financial condition, results of operations or cash flows.

Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain indemnities from sellers for liabilities they may have created.

Our business strategy includes a continuing acquisition program.  From 2010 through 2019, we completed 7 separate significant acquisitions of producing properties with a combined purchase price of $4.6 billion for estimated proved reserves as of the effective dates of the acquisitions of 240.2 MMBOE.  The successful acquisition of producing properties requires assessment of many factors, which are inherently inexact and may be inaccurate, including, but not limited to, the following:

Furthermore, acquisitions pose substantial risks to our business, financial condition, results of operations and cash flows.  The risks associated with acquisitions, either completed or future acquisitions, include, but are not limited to:

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies.  In the course of our due diligence, we may not inspect every well, platform, facility or pipeline.  Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination,

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when they are made.  We may not be able to obtain contractual indemnities from the seller for liabilities that it created.  We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our use of oil and natural gas price hedging contracts involves only a portion of our anticipated production, may limit higher revenues in the future in connection with commodity price increases and may result in significant fluctuations in our net income.

We enter into hedging transactions of our oil and natural gas production revenues to reduce our exposure to fluctuations in the price of oil and natural gas.  Our hedging transactions to date have consisted of financially settled crude oil and natural gas options contracts, primarily costless collars and swaps, placed with major financial institutions.  As of February 20, 2020, we had contracts covering the sale of 31 MMBbl of oil per day for the remainder of 2020 and 6 MMBbl of oil per day for all of 2021.  All of our oil hedges will expire by December 2021.  Refer to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A and the “Derivative Financial Instruments” footnote of the consolidated financial statements in Item 8 of this Annual Report on Form 10-K for pricing information and a more detailed discussion of our hedging transactions.

We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas, or alternatively, we may decide to unwind or restructure the hedging arrangements we previously entered into.  Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.  Hedging transactions may limit the benefit we may otherwise receive from increases in the price for oil and natural gas.  Our three-way collars only provide partial protection against declines in market prices due to the fact that when the market price falls below the sub-floor, the minimum price we will receive will be NYMEX plus the difference between the floor and sub-floor.  Furthermore, if we do not engage in hedging transactions or unwind hedging transactions we previously entered into, then we may be more adversely affected by declines in oil and natural gas prices than our competitors who engage in hedging transactions.  Additionally, hedging transactions may expose us to cash margin requirements.

We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income (loss).  Consequently, we may experience significant net losses, on a non-cash basis, due to changes in the value of our hedges as a result of commodity price volatility.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife.  In certain areas, drilling and other oil and gas activities can only be conducted during certain months.  This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages.  Resulting shortages or high costs could delay our operations, cause temporary declines in our oil and gas production and materially increase our operating and capital costs.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations.

We are not insured against all risks.  Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, results of operations or cash flows.  Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including, but not limited to, the possibility of:

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Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company.  We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented.  In addition, pollution and environmental risks generally are not fully insurable.  If a significant accident or other event occurs and is not fully covered by insurance, then it could adversely affect us.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues and increase capital expenditures.

We operate 88% of our net productive oil and natural gas wells, which represents 92% of our proved developed producing reserves as of December 31, 2019.  If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of our properties.  The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues.  The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, inclusion of other participants in drilling wells, and the use of technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the field.  Operators may also opt to decrease operational activities following a significant decline in, or a sustained period of low, oil or natural gas prices.  Because we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.  Accordingly, while we use reasonable efforts to cause the operator to act in a prudent manner, we are limited in our ability to do so.

We have been an early entrant into new or emerging plays.  As a result, our drilling results in these areas are uncertain, the value of our undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful.

Our drilling results in undeveloped acreage in new or emerging plays are more uncertain than drilling results in areas that are developed and producing.  Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results.  Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.  Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging plays.  For example, during 2018 we recorded an $8 million non-cash charge for the impairment of undeveloped oil and gas properties where we have no current or future plans to drill.  We may also incur such impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.  Additionally, our rights to develop a portion of our undeveloped acreage may expire if not successfully developed or renewed.  Refer to “Acreage” in Item 2 of this Annual Report on Form 10-K for more information relating to the expiration of our rights to develop undeveloped acreage.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation.  We may be required to make large expenditures to comply with governmental regulations.  Matters subject to regulation include, but are not limited to:

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Under these laws, we could be liable for personal injuries, property damage and other damages.  Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and litigation.  Moreover, these laws could change in ways that could substantially increase our costs.  Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition, results of operations or cash flows.  Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions.  For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.  

Our operations may incur substantial costs and liabilities to comply with environmental laws and regulations.

Our oil and gas operations are subject to stringent federal, state and local laws and regulations relating to the release or discharge of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentration of materials that can be released into the environment; limit or prohibit drilling activities on certain lands; and impose substantial liabilities for unauthorized discharges.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations, the imposition of injunctive relief, or certain leases could be cancelled in the event that an agency refuses to issue or delays the issuance of a required permit.  Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previous contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.  Private parties, including the surface owners of properties upon which we drill, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws.  We may not be able to recover some or any of these costs from insurance.  Moreover, federal law and some state laws allow the government to place a lien on real property for costs incurred by the government to address contamination on the property.

Changes in environmental laws and regulations occur frequently and may have a materially adverse impact on our business.  Compliance with any enacted rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance of environmental laws and regulations.

For example, in 2012, the EPA published final rules under the Federal Clean Air Act (the “CAA”) that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.  With regard to production activities, these rules require, among other things, the reduction of volatile organic compound emissions from certain fractured and refractured gas wells for which well completion operations are conducted and, in particular, requiring some of these wells to use reduced emission completions, also known as “green completions”, after January 1, 2015.  These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers and storage vessels.

The requirements were further expanded again in 2016 when the implementation of Subpart OOOOa applied limits on methane emissions to oil and gas facilities and required operators to address leaks, also known as “fugitive emissions.”

However, in September 2019, the EPA proposed two alternative amendments to the Subpart OOOOa Rule.  Both amendments remove all methane-specific requirements from production and processing segments.  The first amendment would also remove transportation and storage facilities from the definition of covered facilities.  The comment period for proposed rule closed on November 25, 2019.  The net effect of any of these amendments, if finalized, would significantly reduce compliance obligations and associated costs.

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The enactment of Senate Bill 19-181 “Protect Public Welfare Oil And Gas Operations” increased the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.

In Colorado, on April 16, 2019, Governor Polis signed into law the final version of Senate Bill 19-181 (“SB 181”), known as the “Protect Public Welfare Oil and Gas Operations” legislation.  SB 181 amends the Oil and Gas Conservation Act and other statutes to change the manner in which oil and gas development is regulated in Colorado and provide the opportunity for greater control to local governments.  The amendments include changes to expand the authority of local governments relating to oil and gas development, as well as rulemaking requirements involving the Colorado Oil and Gas Conservation Commission (“COGCC”) and the Air Quality Control Commission (“AQCC”) that could include more stringent air emission limits for pollutants such as methane and volatile organic carbons and more rigorous permitting requirements.  In December 2019, Colorado’s AQCC adopted new rules targeting air emissions from upstream oil and gas operations, and depending on the results of other ongoing and upcoming rulemakings and actions by COGCC, the Colorado Department of Public Health and Environment and local jurisdictions, SB 181 could result in greater restrictions with respect to oil and gas development in Colorado, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.  Efforts similar to SB 181 are likely to continue in the future, which, if successful, could result in dramatically reducing the area available for future oil and gas development or outright banning oil and gas development in certain jurisdictions. We cannot predict the nature or outcome of future ballot initiatives, legislative actions or other similar efforts, or the effects of implementation of these efforts by local governments. If we are required to cease operating in any of the areas in which we now operate as the result of bans or moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition, and results of operations.

Issues surrounding climate change and greenhouse gas emissions could result in increased operating costs and reduced demand for oil and gas that we produce.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes.  Based on these findings, the EPA has adopted and implemented regulations that restrict emissions of GHG under existing provisions of the CAA.

At present, the EPA may establish GHG permitting requirements for stationary sources already subject to the Prevention of Significant Deterioration (“PSD”)  and Title V requirements of the CAA.  Certain of our equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs.  For any equipment or installation so subject, we may have to incur increased compliance costs to capture related GHG emissions.

In October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements.  The public comment period for the rulemaking concluded on December 16, 2016.  However, although the rulemaking remains on the EPA’s long-term regulatory agenda, no final rule has been published.

In August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units.  The rule, commonly called the “Clean Power Plan”, requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030.  However, in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it was being challenged in court.  On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan and on August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the Clean Power Plan.  The EPA issued the final ACE rule in June 2019.  As expected, over 20 states and public health and environmental organizations have already challenged the rule.  The EPA has sought expedited review in the hopes that the cases will be resolved by the summer of 2020.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, GHG permitting and/or regional GHG “cap and trade” programs.  Most of these “cap and trade” programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.  

Also, in recent years, lawsuits have been brought against other energy companies for matters relating to climate change.  Multiple states and localities have also initiated investigations in climate-change related matters.  While the current suits focus on a variety of issues, at

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their core they seek compensation for the effects of climate change from companies with ties to GHG emissions.  It is currently unknown what the outcome of these types of actions may be, but the costs of defending against such actions may rise.  Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our assets and operations.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.  Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers.  These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.  Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.

A low ESG or sustainability score could result in the exclusion of our common shares from consideration by certain investment funds and a negative perception of us by certain investors.

Certain organizations that provide corporate governance and other corporate risk information to investors and shareholders have developed scores and ratings to evaluate companies and investment funds based upon environmental, social and governance (“ESG”) or sustainability metrics.  Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders.  Many investment funds focus on positive ESG business practices and sustainability scores when making investments.  In addition, investors, particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance.  Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision.  Consequently, a low sustainability score could result in exclusion of our common shares from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of us by certain investors.

We may be negatively impacted by litigation and legal proceedings.

We are subject from time to time, and in the future may become subject, to litigation claims.  These claims and legal proceedings are typically claims that arise in the normal course of business and include, without limitation, claims relating to environmental, safety and health matters, commercial or contractual disputes with suppliers and customers, claims regarding ownership of mineral interests, including from royalty owners, claims regarding acquisitions and divestitures, regulatory matters and employment and labor matters.  We may also become subject to governmental or regulatory proceedings.  The outcome of such claims and legal proceedings cannot be predicted with certainty and some may be disposed of unfavorably to us.  Among other pending litigation claims, the Company is involved with litigation related to a payment arrangement with a third party which currently claims damages up to $41 million, as well as court costs and interest.  We also may not have insurance that covers such claims and legal proceedings.  Successful claims or litigation against us for significant amounts could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows.  Further, even if successful in resolving a claim or legal proceeding, such process could require the attention of members of our senior management, reducing the time they have available to devote to managing our business, and require us to incur substantial legal expenses.

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The loss of senior management or technical personnel could adversely affect us.

To a large extent, we depend on the services of our senior management and technical personnel.  The loss of the services of our senior management or technical personnel, including Bradley J. Holly, Chairman, President and Chief Executive Officer; Bruce DeBoer, Chief Administrative Officer, General Counsel and Corporate Secretary; Charles J. Rimer, Chief Operating Officer; Correne S. Loeffler, Chief Financial Officer; and Timothy M. Sulser, Chief Corporate Development and Strategy Officer, could have a material adverse effect on our business, financial condition, results of operations or cash flows.  We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in joint ventures, partnerships, and other strategic alternatives that may enhance shareholder value, any of which may result in the use of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit of such transactions.

We expect to continue to consider acquisitions, dispositions, investments in joint ventures, partnerships, and other strategic alternatives with the objective of maximizing shareholder value.  The Board and our management may from time to time be engaged in evaluating potential transactions and other strategic alternatives.  In addition, from time to time, we may engage financial advisors, enter into non-disclosure agreements, conduct discussions, and undertake other actions that may result in one or more transactions.  Although there would be uncertainty that any of these activities or discussions would result in definitive agreements or the completion of any transaction, we may devote a significant amount of our management resources to analyzing and pursuing such a transaction, which could negatively impact our operations, and may impair our ability to retain and motivate key personnel.  In addition, we may incur significant costs in connection with seeking such transactions or other strategic alternatives regardless of whether the transaction is completed.  In the event that we consummate an acquisition, disposition, partnership or other or strategic alternative in the future, we cannot be certain that we would fully realize the potential benefit of such a transaction and cannot predict the impact that such strategic transaction might have on our operations or stock price.  Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, market conditions, industry trends, regulatory limitations and the interest of third parties in us and our assets.  There can be no assurance that the exploration of strategic alternatives will result in any specific action or transaction.  Further, any such strategic alternative may not ultimately lead to increased shareholder value.  We do not undertake to provide updates or make further comments regarding the evaluation of strategic alternatives, unless otherwise required by law.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

In order to finance acquisitions of additional producing or undeveloped properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means.  These changes in capitalization may significantly affect our risk profile.  Additionally, significant acquisitions or other transactions can change the character of our operations and business.  The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties.  Furthermore, we may not be able to obtain external funding for additional future acquisitions or other transactions on economically acceptable terms or at all.

Competition in the oil and gas industry and from alternative energy sources is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, obtaining investment capital, securing oilfield goods and services, marketing oil and natural gas products and attracting and retaining qualified personnel.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate.  Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our resources allow.  Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

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We also face indirect competition from alternative energy sources, including wind, solar, nuclear and electric power.  The proliferation of alternative energy sources and businesses that provide such alternative energy sources may decrease the demand for oil and natural gas products.  Decreased demand for our products could adversely affect our business, financial condition, results of operations or cash flows.

In connection with the passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, new regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to manage our risks related to oil and gas commodity price volatility.

On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law.  This financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared.  In addition, the legislation provides an exemption from mandatory clearing requirements based on regulations to be developed by the Commodity Futures Trading Commission (the “CFTC”) and the SEC for transactions by non-financial institutions, such as us, to hedge or mitigate commercial risk.  At the same time, the legislation includes provisions under which the CFTC may impose collateral requirements for transactions, including those that are used to hedge commercial risk.  However, during drafting of the legislation, members of Congress adopted report language and issued a public letter stating that it was not their intention to impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk.  Final rules on major provisions in the legislation, like new margin requirements, may be established through rulemakings.  Although we cannot predict the ultimate outcome of these rulemakings, new regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and to otherwise manage our financial risks related to volatility in oil and gas commodity prices.

We depend on computer and telecommunications systems, and failures in our systems or cybersecurity attacks could have an adverse effect on our business, financial condition, results of operations or cash flows.

Our business has become increasingly dependent upon digital technologies to conduct day-to-day operations, including information systems, infrastructure and cloud applications.  We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business.  In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties.  We rely on such systems to process, transmit and store electronic information, including financial records and personally identifiable information such as contractor, investor and payroll data, and to manage or support a variety of business processes, including our supply chain, pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions.  

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have increased in frequency.  A cyber-attack could include unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites.  It is possible that we could incur interruptions from cybersecurity attacks, computer viruses or malware, or that third party service providers could cause a breach of our data.  We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls over personally identifiable information and contractor data; however, any interruptions to our arrangements with third parties for our computing and communications infrastructure or any other interruptions to, or breaches of, our information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt our business operations.  

Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future cyber-attacks than other targets.  The various procedures, facilities, infrastructure and controls we utilize to monitor these threats and mitigate our exposure to such threats are costly and labor intensive.  Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring.  We do not expect to obtain or maintain specialized insurance for possible liability or loss resulting from a cyber-attack on our assets that may shut down all or part of our business.  However, as cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.  State and federal cybersecurity legislation could also impose new requirements, which could increase our cost of doing business.  

To our knowledge we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer material losses in the future either as a result of an interruption to or a breach of our systems or those of our third party

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vendors and service providers.  A cyber incident involving our information systems and related infrastructure, or that of third parties, could disrupt our business plans and negatively impact our operations in the following ways, among others, any of which could have an adverse effect on our reputation, business, financial condition, results of operations or cash flows:

Item 1B.      Unresolved Staff Comments

None.

Item 2.       Properties

Summary of Oil and Gas Properties and Projects

Northern Rocky Mountains

Our Northern Rocky Mountains operations include our properties in the Williston Basin of North Dakota and Montana targeting the Bakken and Three Forks formations and encompassing approximately 756,800 gross (476,300 net) developed and undeveloped acres as of December 31, 2019.  Our estimated proved reserves in the Northern Rocky Mountains as of December 31, 2019 were 453.5 MMBOE (54% oil), which represented 93% of our total estimated proved reserves and contributed 112.0 MBOE/d of average daily production in the fourth quarter of 2019.

Across our acreage in the Williston Basin, we have implemented customized, right-sized completion designs which utilize the optimum volume of proppant, diversion, fluids and frac stages to increase well performance while reducing cost.  We plan to continue to use right-sized completion designs on wells we drill in 2020, while also utilizing state-of-the-art drilling rigs, high-torque mud motors and evolving 3-D bit cutter technology to reduce time-on-location and total well cost. Our engineers have worked with service providers to optimize fluid systems and bit designs to increase drill rate and hole cleaning resulting in higher capital efficiency in the drilling program. As of December 31, 2019, we had four rigs active in the Williston Basin.

Central Rocky Mountains

Our Central Rocky Mountains operations include properties at our Redtail field in the Denver-Julesburg Basin (“DJ Basin”) in Weld County, Colorado targeting the Niobrara and Codell/Fort Hays formations and encompassing approximately 96,400 gross (84,600 net) developed and undeveloped acres as of December 31, 2019.  Our estimated proved reserves in the Central Rocky Mountains as of December 31, 2019 were 23.1 MMBOE (61% oil), which represented 5% of our total estimated proved reserves and contributed 10.4 MBOE/d of average daily production in the fourth quarter of 2019.

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We have established production in the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations.  We completed 22 drilled uncompleted wells (“DUCs”) in our Redtail field during the first half of 2018, and no additional wells were drilled or completed in 2019.  During 2019 we worked on maintaining base production in this area with improved artificial lift techniques and reductions in lease operating expenses.

Our Redtail gas plant processes the associated gas produced from our wells in this area, and has a current inlet capacity of 50 MMcf/d.  As of December 31, 2019, the plant was processing 22 MMcf/d.

Other

Our other operations primarily relate to non-core assets in Colorado, Mississippi, North Dakota, Texas and Wyoming.  As of December 31, 2019, these properties contributed 8.8 MMBOE (83% oil) of proved reserves to our portfolio of operations, which represented 2% of our total estimated proved reserves and contributed 0.6 MBOE/d of average daily production in the fourth quarter of 2019.

Reserves

As of December 31, 2019 and 2018, all of our oil and gas reserves were attributable to properties within the United States.  A summary of our proved oil and gas reserves as of December 31, 2019 and 2018 based on average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2019 and 2018, respectively) is as follows:

​

Proved reserves.  Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Total extensions and discoveries of 34.0 MMBOE in 2019 were primarily attributable to successful drilling in the Williston Basin.  Both the new wells drilled in this area as well as the PUD locations added as a result of drilling increased our proved reserves.

Sales of minerals in place totaled 4.9 MMBOE during 2019 and were primarily attributable to the disposition of certain non-operated properties in North Dakota as further described in “Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K.

In 2019, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17.9 MMBOE.  Included in this change were upward revisions of 48.0 MMBOE to proved undeveloped reserves primarily located in the Williston Basin in locations where we have significant development activity and past drilling success.  Offsetting these upward reserve revisions were: (i) 32.9 MMBOE of downward adjustments caused by lower crude oil, NGL and natural gas prices incorporated into our reserve estimates at December 31, 2019 as compared to December 31, 2018, (ii) 19.3 MMBOE of downward adjustments primarily attributable to reservoir analysis and well performance across our Northern and Central Rockies assets and (iii) 13.7 MMBOE of proved undeveloped reserves no longer expected to be developed within five years from their initial recognition.  

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Proved undeveloped reserves.  Our PUD reserves decreased 18% or 27.7 MMBOE on a net basis from December 31, 2018 to December 31, 2019.  The following table provides a reconciliation of our PUDs for the year ended December 31, 2019:

​

During 2019, we incurred $475 million in capital expenditures, or $11.10 per BOE, to drill and bring on-line 42.8 MMBOE of PUD reserves.  In addition, we added 19.4 MMBOE of PUDs from extensions and discoveries during the year primarily due to successful drilling in the Williston Basin.  We have made an investment decision and adopted a development plan to drill all of our individual PUD locations within five years of the date such PUDs were added.  In that regard, under our current 2020 development plan, we expect to convert approximately 48.1 MMBOE of PUDs to proved developed reserves during the year.

Preparation of reserves estimates.  We maintain adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based.  The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data.  All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans.  Current revenue and expense information is obtained from our accounting records, which are subject to our internal controls over financial reporting.  Internal controls over financial reporting are assessed for effectiveness annually using the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  All current financial data such as commodity prices, lease operating expenses, transportation, gathering, compression and other expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete.  Our current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated into the reserve database as well and verified to ensure their accuracy and completeness.  Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, our independent engineering firm Cawley, Gillespie & Associates, Inc. (“CG&A”) meets with our technical personnel in our Denver office to review field performance and future development plans.  Following this review, the reserve database and supporting data is furnished to CG&A so that they can prepare their independent reserve estimates and final report.  Access to our reserve database is restricted to specific members of the reservoir engineering department.

CG&A is a Texas Registered Engineering Firm.  Our primary contact at CG&A is Mr. W. Todd Brooker, President.  Mr. Brooker is a State of Texas Licensed Professional Engineer.  Refer to Exhibit 99.2 of this Annual Report on Form 10-K for the Report of Cawley, Gillespie & Associates, Inc. and further information regarding the professional qualifications of Mr. Brooker.

Trina Medina, our Director of Reservoir Engineering, is responsible for overseeing the preparation of the reserves estimates.  She has more than 25 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional, unconventional and secondary recovery evaluation and development projects, including corporate reserves estimations.  Ms. Medina holds a Bachelor of Science degree in petroleum engineering from the Universidad Central de Venezuela, a Master of Science degree in reservoir engineering from Texas A&M University and a Master of Science degree in reservoir geoscience from the Institut Francais du Petrole.  Ms. Medina is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

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Acreage

The following table summarizes gross and net developed and undeveloped acreage by core area at December 31, 2019.  Net acreage represents our percentage ownership of gross acreage.  Acreage in which our interest is limited to royalty and overriding royalty interests has been excluded.

Production History

The following table presents historical information about our produced oil and gas volumes:

Productive Wells

The following table summarizes gross and net productive oil and natural gas wells by core area at December 31, 2019.  A net well represents our percentage ownership of a gross well.  Wells in which our interest is limited to royalty and overriding royalty interests are excluded.

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Oil and Gas Drilling Activity

We are engaged in numerous drilling activities on properties presently owned, and we intend to drill or develop other properties acquired in the future.  The following table sets forth our oil and gas drilling activity for the last three years.  A dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.  A productive well is an exploratory, development or extension well that is not a dry well.  The information below should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found.

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As of December 31, 2019, we had four operated drilling rigs active on our properties in our Northern Rocky Mountains area.  As of December 31, 2019, we had 129 gross (57.1 net) operated and non-operated wells in the process of drilling, completing or waiting on completion.

Hydraulic Fracturing

Hydraulic fracturing is a common practice in the oil and gas industry that is used to stimulate production of hydrocarbons from tight oil and gas formations.  The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production.  This process has typically been regulated by state oil and gas commissions.  However, as described in more detail in “Business – Regulation – Environmental Regulations – Hydraulic Fracturing” in Item 1 of this Annual Report on Form 10-K, the EPA has initiated the regulation of hydraulic fracturing, other federal agencies are examining hydraulic fracturing, and federal legislation is pending with respect to hydraulic fracturing.  We have utilized hydraulic fracturing in the completion of our wells in our most active areas located in the states of North Dakota, Montana and Colorado and we plan to continue to utilize this completion methodology.

Substantially all of our 126.6 MMBOE of proved undeveloped reserves are associated with hydraulic fracture treatments.

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We are not aware of any environmental incidents, citations or suits that have occurred during the last three years related to hydraulic fracturing operations involving oil and gas properties that we operate or in which we own a non-operated interest.

In order to minimize any potential environmental impact from hydraulic fracture treatments, we have taken the following steps:

While we do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations, we do have general liability and excess liability insurance policies that we believe would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Delivery Commitments

Our production sales agreements contain customary terms and conditions for the oil and natural gas industry, generally provide for sales based on prevailing market prices in the area, and generally have terms of one year or less.

As of December 31, 2019, we have entered into three physical delivery contracts which require us to deliver fixed volumes of crude oil.  One of these contracts is tied to crude oil production from the Williston Basin and requires delivery of 10 MBbl/d for a term of seven years.  The effective date of this contract is contingent upon the completion of certain related pipelines, which are currently expected to be brought online in 2021.  Under the terms of this contract, if we fail to deliver the committed volumes we will be required to pay a deficiency payment of $5.75 per undelivered Bbl, subject to upward adjustment, over the duration of the contract.  However, we believe that our production and reserves are sufficient to fulfill the delivery commitment in the Williston Basin, and we therefore expect to avoid any payments for deficiencies under this contract.

Our two remaining physical delivery contracts are effective as of December 31, 2019.  One of these contracts is tied to oil production at our Sanish field in Mountrail County, North Dakota and is effective for a term of seven years ending May 31, 2024.  The other contract

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is tied to oil production at our Redtail field in Weld County, Colorado and terminates in April 2020.  The following table summarizes our Sanish and Redtail delivery commitments as of December 31, 2019:

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Under the terms of the Sanish contract, if we fail to deliver the committed volumes we will be required to pay a deficiency payment of $7.00 per undelivered Bbl, subject to upward adjustment, over the duration of the contract.  However, we believe that our production and reserves are sufficient to fulfill the delivery commitment at our Sanish field, and we therefore expect to avoid any payments for deficiencies under this contract.

Under the terms of the Redtail contract, if we fail to deliver the committed volumes we are required to pay a deficiency payment that currently totals $5.24 per undelivered Bbl over the remaining term of the contract.  We have determined that it is not probable that future oil production from our Redtail field will be sufficient to meet the minimum volume requirements specified in the related physical delivery contract, and as a result, we expect to make deficiency payments for any shortfalls in delivering the minimum committed volumes.  We recognize any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. During 2019, 2018 and 2017, total deficiency payments under this contract, as well as a second Redtail contract that we terminated in February 2018, amounted to $64 million, $39 million and $66 million, respectively.

Item 3.       Legal Proceedings

We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.  While the outcome of these lawsuits and claims cannot be predicted with certainty, it is management’s opinion that the loss for any litigation matters and claims we are involved in that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on our consolidated financial position, cash flows or results of operations.

We are involved in litigation related to a payment arrangement with a third party which currently claims damages up to $41 million, as well as court costs and interest, that is scheduled to go to trial in May 2020.  Certain amounts have been accrued in accrued liabilities and other in the consolidated balance sheet as of December 31, 2019 and general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2019 based on the determination that it is probable that a loss has been incurred and can be reasonably estimated.

Item 4.       Mine Safety Disclosures

Not applicable.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following table sets forth certain information, as of February 20, 2020, regarding the executive officers of Whiting Petroleum Corporation:

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The following biographies describe the business experience of our executive officers:

Bradley J. Holly joined us in November 2017 upon his appointment as director and election as President and Chief Executive Officer.  Mr. Holly was appointed Chairman of the Board in May 2018.  Mr. Holly has 25 years of experience in the oil and gas industry.  Prior to joining Whiting, he held various management and technical positions during his 20 years at Anadarko Petroleum Corporation including Executive Vice President, U.S. Onshore Exploration and Production; Senior Vice President, U.S. Onshore Exploration and Production; Senior Vice President, Operations; Vice President, Operations for the Southern and Appalachia Region; among others.  He began his career in 1994 with Amoco Corporation.  Mr. Holly holds a Bachelor of Science degree in petroleum engineering from Texas Tech University, and he is a graduate of the Harvard Business School’s Advanced Management Program.

Bruce R. DeBoer joined us as Vice President, General Counsel and Secretary in January 2005 and was elected Chief Administrative Officer, General Counsel and Secretary effective August 2019.  Previously, Mr. DeBoer served as Vice President, General Counsel and Corporate Secretary of Tom Brown, Inc., an independent oil and gas exploration and production company.  Mr. DeBoer has 40 years of experience in managing the legal departments of several independent oil and gas companies.  He holds a Bachelor of Science degree in political science from South Dakota State University and received his J.D. and MBA degrees from the University of South Dakota.

Correne S. Loeffler joined us in August 2019 as Chief Financial Officer.  Ms. Loeffler has 14 years of oil and gas experience.  She  previously served as Vice President, Finance and Treasurer for Callon Petroleum Company for two years and also served as Interim Chief Financial Officer for a portion of that time.  Prior to joining Callon, Ms. Loeffler was Executive Director with JPMorgan Securities, LLC where she was employed in the Corporate Client Bank Group for 12 years.  She started her career as a consultant at Accenture.  Ms. Loeffler holds a Bachelor of Arts degree from Indiana University and a Master of Business Administration degree from the University of Texas.

Charles J. Rimer joined us in November 2018 as Chief Operating Officer.  Mr. Rimer has 37 years of experience in the industry.  Prior to joining Whiting, he held various management and technical positions during his 16 years at Noble Energy, Inc. including Senior Vice President, Global Services; Senior Vice President, U.S. Onshore; Senior Vice President, Global EHSR and Operations Services; Vice President of Operations Services; among others.  He also held various management and technical positions at Aspect Resources, Vastar Resources and ARCO Oil & Gas Company where he began his career in 1983.  Mr. Rimer holds a Bachelor of Arts degree in business from Furman University and Bachelor of Science degree in petroleum engineering from the University of Texas.

Timothy M. Sulser joined us in September 2018 as Chief Corporate Development and Strategy Officer.  Mr. Sulser has 21 years of oil and gas experience.  He co-founded Salt Creek Oil and Gas, LLC in 2015 after five years as an investment banker with Tudor, Pickering, Holt & Co. (“TPH”), most recently heading its Denver office.  While at TPH, Mr. Sulser advised upstream clients on acquisitions and divestitures and energy capital markets.  Prior to joining TPH, he worked as a reservoir engineer for reserve engineering consultant Netherland, Sewell, and Associates in Houston, Texas.  He started his career with Marathon Oil Company in Lafayette, Louisiana.  Mr. Sulser holds a Bachelor of Science degree in petroleum engineering from Montana Tech and a Master of Science degree in operations research from Columbia University.

Sirikka R. Lohoefener joined us in June 2006 as a Senior Financial Accountant, became Financial Reporting Manager in January 2011 and Controller in March 2015.  She was appointed Controller and Treasurer in March 2017, Vice President, Controller and Treasurer in December 2018 and Vice President and Controller in October 2019 and serves as the Company’s designated principal accounting officer.  Prior to joining Whiting, Ms. Lohoefener spent five years with Wagner, Burke & Barnes, LLP, a public accounting firm previously

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based in Golden, Colorado.  She holds a Master of Accountancy degree from the University of Missouri and is a Certified Public Accountant.

Executive officers are elected by, and serve at the discretion of, the Board of Directors.  There are no family relationships between any of our directors or executive officers.

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PART II

Item 5.        Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Whiting Petroleum Corporation’s common stock is traded on the New York Stock Exchange under the symbol “WLL”.  On February 20, 2020, there were 444 holders of record of our common stock.

On November 8, 2017, our Board of Directors approved a reverse stock split of our common stock at a ratio of one-for-four and a reduction in the number of authorized shares of our common stock from 600,000,000 shares to 225,000,000.  Our common stock began trading on a split-adjusted basis on November 9, 2017 upon opening of the markets.  All share and per share amounts in this Annual Report on Form 10-K for periods prior to November 2017 have been retroactively adjusted to reflect the reverse stock split.

We have not paid any cash dividends on our common stock since we were incorporated in July 2003, and we do not anticipate paying any such dividends on our common stock in the foreseeable future.  We currently intend to retain future earnings, if any, to finance the expansion of our business.  Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our financial position, cash flows, results of operations, capital requirements and investment opportunities.  

Information relating to compensation plans under which our equity securities are authorized for issuance is set forth in Part III, Item 12 of this Annual Report on Form 10-K.

The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.

The following graph compares on a cumulative basis changes since December 31, 2014 in (a) the total stockholder return on our common stock with (b) the total return on the Standard & Poor’s Composite 500 Index and (c) the total return on the Dow Jones U.S. Exploration & Production Index.  Such changes have been measured by dividing (a) the sum of (i) the cumulative amount of dividends for the measurement period, assuming dividend reinvestment, and (ii) the difference between the price per share at the end of and the beginning of the measurement period, by (b) the price per share at the beginning of the measurement period.  The graph assumes $100 was invested on December 31, 2014 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones U.S. Exploration & Production Index, respectively.

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Item 6.       Selected Financial Data

The consolidated statements of operations and statements of cash flows information for the years ended December 31, 2019, 2018 and 2017 and the consolidated balance sheet information at December 31, 2019 and 2018 are derived from our audited financial statements included elsewhere in this report.  The consolidated statements of operations and statements of cash flows information for the years ended December 31, 2016 and 2015 and the consolidated balance sheet information at December 31, 2017, 2016 and 2015 are derived from audited financial statements that are not included in this report.  Our historical results include the results from our recent proved property acquisition of properties in North Dakota and Montana on July 31, 2018.  In addition, our historical results also include the effects of our recent property divestitures beginning on the following closing dates: non-operated properties in North Dakota, July 29, 2019 and August 15, 2019; properties in the Fort Berthold Indian Reservation area, September 1, 2017; gas processing plants and related gathering systems in North Dakota, January 1, 2017; properties in the North Ward Estes field, July 27, 2016; water facilities in Colorado, December 16, 2015; non-core properties in various fields across multiple states, December 15, 2015, November 12, 2015 and June 10, 2015; and the underlying properties of Whiting USA Trust I, April 15, 2015.  For a discussion of other material factors affecting the comparability of the information presented below, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report on Form 10-K.

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Item 7.      Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context otherwise requires, the terms “Whiting”, “we”, “us”, “our” or “ours” when used in this Item refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC, Whiting Resources Corporation and Whiting Programs, Inc.  When the context requires, we refer to these entities separately.  This document contains forward-looking statements, which give our current expectations or forecasts of future events.  Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of statements.

Overview

We are an independent oil and gas company engaged in development, production, acquisition and exploration activities primarily in the Rocky Mountains region of the United States.  Our current operations and capital programs are focused on organic drilling opportunities and on the development of previously acquired properties, specifically on projects that we believe provide the greatest potential for repeatable success and production growth, while selectively pursuing acquisitions that complement our existing core properties and exploring other basins where we can apply our existing knowledge and expertise to build production and add proved reserves.  As a result of lower crude oil prices during 2017 and 2018, we significantly reduced our level of capital spending and focused our drilling activity on projects that provide the highest rate of return, while closely aligning our capital spending with cash flows generated from operations.  During 2019, we focused on developing our large resource play in the Williston Basin of North Dakota and Montana, while continuing to closely align our capital spending with cash flows generated from operations.  We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return or when the property no longer matches the profile of properties we desire to own, such as the asset sales discussed below under “Acquisition and Divestiture Highlights” and in the “Acquisitions and Divestitures” footnote in the notes to the consolidated financial statements.

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as oil and gas prices, economic, political and regulatory developments, competition from other sources of energy, and the other items discussed under the caption “Risk Factors” in Item 1A of this Annual Report on Form 10-K.  Oil and gas prices historically have been volatile and may fluctuate widely in the future.  The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas prices since the first quarter of 2018:

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Lower oil, NGL and natural gas prices may not only decrease our revenues on a per unit basis, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our oil and gas reserve quantities.  Substantial and extended declines in oil, NGL and natural gas prices have resulted, and may result, in impairments of our proved oil and gas properties or undeveloped acreage (such as the impairments discussed below under “Results of Operations”) and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures.  In addition, lower commodity prices may reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders, as occurred with our most recent semi-annual redetermination where the borrowing base was lowered from $2.25 billion to $2.05 billion in October 2019.  Upon a redetermination, if total outstanding credit exposure exceeds the redetermined borrowing base, we will be required to prepay outstanding borrowings in an aggregate principal amount equal to such excess in six substantially equal monthly installments.  Alternatively, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives.

For a discussion of material changes to our proved reserves from December 31, 2018 to December 31, 2019 and our ability to convert PUDs to proved developed reserves, refer to “Reserves” in Item 2 of this Annual Report on Form 10-K.  Additionally, for a discussion relating to the minimum remaining terms of our leases, refer to “Acreage” in Item 2 of this Annual Report on Form 10-K.

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2019 Highlights and Future Considerations

Operational Highlights

Northern Rocky Mountains – Williston Basin

Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations.  Net production from the Williston Basin averaged 112.0 MBOE/d for the fourth quarter of 2019, representing a 1% increase from 111.4 MBOE/d in the third quarter of 2019.  Across our acreage in the Williston Basin, we have implemented customized, right-sized completion designs which utilize the optimum volume of proppant, fluids, and frac stages to increase well performance while reducing cost.  We have increased stages pumped per day by focusing on new technologies such as quick-install wellhead connections and frac plug innovations.  We plan to continue to use right-sized completion designs on wells we drill in 2020, while also utilizing state-of-the-art drilling rigs, high-torque mud motors and 3-D bit cutter technology to reduce time-on-location and total well cost.  As of December 31, 2019, we had four rigs active in the Williston Basin.  We drilled 31 wells and put 35 wells on production in this area during the fourth quarter of 2019.  First quarter 2020 production has been impacted by severe weather conditions and associated electric submersible pump failures on multiple high value wells.  We estimate that this will impact first quarter 2020 production results by approximately 5 MBOE/d.

Central Rocky Mountains – Denver-Julesburg Basin

Our Redtail field in the Denver-Julesburg Basin (“DJ Basin”) in Weld County, Colorado targets the Niobrara and Codell/Fort Hays formations.  Net production from the Redtail field averaged 10.4 MBOE/d in the fourth quarter of 2019, representing a 7% decrease from 11.2 MBOE/d in the third quarter of 2019.  We have established production in the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations.  We completed 22 drilled uncompleted wells (“DUCs”) in our Redtail field during the first half of 2018, and no additional wells were drilled or completed in 2019.  During 2019 we worked on maintaining base production with improved artificial lift techniques and reductions in lease operating expenses.  

Our Redtail gas plant processes the associated gas produced from our wells in this area, and has a current inlet capacity of 50 MMcf/d.  As of December 31, 2019, the plant was processing 22 MMcf/d.

Financing Highlights

In September 2019, we paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of our 2020 Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes.

In September 2019, we paid $24 million to repurchase $25 million aggregate principal amount of our 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the notes.  In October 2019, we paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes.

We financed the tender offer and repurchases with borrowings under our credit agreement.  Refer to the “Long Term Debt” footnote in the notes to the consolidated financial statements for more information on the tender offer and repurchases.

In October 2019, the borrowing base under our credit agreement was reduced from $2.25 billion to $2.05 billion in connection with the November 1, 2019 regular borrowing base redetermination, with no change to the aggregate commitments of $1.75 billion.

2020 Exploration and Development Budget

Our 2020 exploration and development (“E&D”) budget is a range of $585 million to $620 million, which we expect to fund substantially with net cash provided by our operating activities and cash on hand, and represents a decrease from the $778 million incurred on E&D expenditures during 2019.  This reduced spending is primarily attributable to our commitment to closely align capital spending with cash flows generated from operations.  To the extent net cash provided by operating activities is higher or lower than currently anticipated, we would generate more or less free cash flow than we currently anticipate, and may adjust our E&D budget and attempt to enter into agreements with industry partners, divest certain oil and gas property interests, adjust borrowings outstanding under our credit facility or access the capital markets as necessary.  Approximately 90% of the midpoint of our 2020 E&D budget currently is allocated

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to drilling and completion activity.  Of our existing development opportunities, we believe this allocation of our capital presents the opportunity for the highest return and most efficient use of our capital.

Acquisition and Divestiture Highlights

On July 29, 2019, we completed the divestiture of our interests in 137 non-operated, producing oil and gas wells located in McKenzie, Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $27 million (before closing adjustments).  

On August 15, 2019, we completed the divestiture of our interests in 58 non-operated, producing oil and gas wells located in Richland County, Montana and Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $26 million (before closing adjustments).  

On a combined basis, the divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2018 and our April 2019 average daily production.

On January 9, 2020, we completed the divestiture of our interests in 30 non-operated, producing oil and gas wells and related undeveloped acreage located in McKenzie County, North Dakota for aggregate sales proceeds of $25 million (before closing adjustments).  The divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2019 and 1% of our average daily production for the year ended December 31, 2019.

Restructuring

On July 31, 2019, we executed a workforce reduction as part of an organizational redesign and cost reduction strategy to better align our business with the current operating environment and drive long-term value.  We incurred a one-time net charge of $8 million to general and administrative expense during 2019 related to this restructuring.

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Results of Operations

The following table sets forth selected operating data for the periods indicated: