UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
|☒||ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
For the fiscal year ended December 31, 2020
|☐||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 001-33999
NORTHERN OIL AND GAS, INC.
(Exact Name of Registrant as Specified in Its Charter)
(State or Other Jurisdiction of Incorporation or Organization)
|(I.R.S. Employer Identification No.)|
601 Carlson Pkwy – Suite 990, Minnetonka, Minnesota 55305
(Address of Principal Executive Offices) (Zip Code)
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
|Title of Each Class|| ||Trading Symbol(s)||Name of Each Exchange On Which Registered|
|Common Stock, $0.001 par value|| ||NOG||NYSE American|
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 ý
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 ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ☐
Indicate by check mark whether the registrant has submitted electronically 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 ý 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:
Large Accelerated Filer ☐ Accelerated Filer ý Non-Accelerated Filer ☐
Smaller Reporting Company ☐ Emerging Growth Company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ý
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sale price as reported by the NYSE American) was approximately $266.2 million.
As of March 9, 2020, the registrant had 60,421,200 shares of common stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement related to the registrant’s 2021 Annual Meeting of Stockholders are incorporated by reference into Part III of this report for the year ended December 31, 2020.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.
From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production and sales, cash flows, and trends or operating results also constitute such forward-looking statements.
Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on our properties, our ability to acquire additional development opportunities, potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from our acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on our company’s cash position and levels of indebtedness, changes in our reserves estimates or the value thereof, disruptions to our company’s business due to acquisitions and other significant transactions, general economic or industry conditions, nationally and/or in the communities in which our company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, our ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting our company’s operations, products and prices, and the COVID-19 pandemic and its related economic repercussions and effect on the oil and natural gas industry.
We have based any forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results described in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in “Item 1A. Risk Factors” and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.
Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the United States Securities and Exchange Commission (the “SEC”) which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.
GLOSSARY OF TERMS
Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
The following definitions shall apply to the technical terms used in this report.
Terms used to describe quantities of crude oil and natural gas:
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.
“Boe.” A barrel of oil equivalent and is a standard convention used to express crude oil, NGL and natural gas volumes on a comparable crude oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or NGL.
“Boepd.” Boe per day.
“Btu or British Thermal Unit.” The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
“MBbl.” One thousand barrels of crude oil, condensate or NGLs.
“MBoe.” One thousand Boe.
“Mcf.” One thousand cubic feet of natural gas.
“MMBbl.” One million barrels of crude oil, condensate or NGLs.
“MMBoe.” One million Boe.
“MMBtu.” One million British Thermal Units.
“MMcf.” One million cubic feet of natural gas.
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.
Terms used to describe our interests in wells and acreage:
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs, and/or natural gas.
“Conventional play.” An area that is believed to be capable of producing crude oil, NGLs, and natural gas occurring in discrete accumulations in structural and stratigraphic traps.
“Developed acreage.” Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Development well.” A well drilled within the proved area of a crude oil, NGL, or natural gas reservoir to the depth of a stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extracting proved crude oil, NGL, or natural gas reserves.
“Differential.” The difference between a benchmark price of crude oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Exploratory well.” A well drilled to find and produce crude oil, NGLs, or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil, NGLs, or natural gas in another reservoir, or to extend a known reservoir.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
“Gross acres or Gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Held by operations.” A provision in an oil and gas lease that extends the stated term of the lease as long as drilling operations are ongoing on the property.
“Held by production.” A provision in an oil and gas lease that extends the stated term of the lease as long as the property produces a minimum quantity of crude oil, NGLs, and natural gas.
“Hydraulic fracturing.” The technique of improving a well’s production by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
“Infill well.” A subsequent well drilled in an established spacing unit of an already established productive well in the spacing unit. Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Net acres.” The percentage ownership of gross acres. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).
“Net well.” A well that is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.
“NYMEX.” The New York Mercantile Exchange.
“OPEC.” The Organization of Petroleum Exporting Countries.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible crude oil, NGLs and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Unconventional play.” An area believed to be capable of producing crude oil, NGLs, and/or natural gas occurring in cumulations that are regionally extensive but require recently developed technologies to achieve profitability. These areas tend to have low permeability and may be closely associated with source rock as this is the case with crude oil and natural gas shale, tight crude oil and natural gas sands and coal bed methane.
“Undeveloped acreage.” Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
“West Texas Intermediate or WTI.” A light, sweet blend of oil produced from the fields in West Texas.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“Workover.” Operations on a producing well to restore or increase production.
Terms used to assign a present value to or to classify our reserves:
“Possible reserves.” The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.
“Pre-tax PV-10% or PV-10.” The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.
“Probable reserves.” The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.
“Proved developed producing reserves (PDPs).” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil, NGLs, and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved developed non-producing reserves (PDNPs).” Proved crude oil, NGLs, and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.
“Proved reserves.” The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences 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.
“Proved undeveloped drilling location.” A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or “PUDs.” 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 development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves will not 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 tests in the area and in the same reservoir or an analogous reservoir.
(i) The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil, NGLs or natural gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the twelve-month period prior to 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 on future conditions.
“Standardized measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
NORTHERN OIL AND GAS, INC.
TABLE OF CONTENTS
| || ||Page|
|Unresolved Staff Comments|
|Mine Safety Disclosures|
| || |
|Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities|
|Management’s Discussion and Analysis of Financial Condition and Results of Operations|
|Quantitative and Qualitative Disclosures About Market Risk|
|Financial Statements and Supplementary Data|
|Changes in and Disagreements With Accountants on Accounting and Financial Disclosure|
|Controls and Procedures|
| || || |
|Directors, Executive Officers and Corporate Governance|
|Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters|
|Certain Relationships and Related Transactions, and Director Independence|
|Principal Accountant Fees and Services|
| || || |
|Exhibits and Financial Statement Schedules|
|Form 10-K Summary|
Index to Financial Statements
NORTHERN OIL AND GAS, INC.
ANNUAL REPORT ON FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2020
Item 1. Business
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties, primarily in the Bakken and Three Forks formations within the Williston Basin in North Dakota and Montana. We believe the location, size and concentration of our acreage position in one of North America’s leading unconventional oil-resource plays provide us with drilling and development opportunities that will result in significant long-term value.
Our primary focus is investing in non-operated minority working and mineral interests in oil and gas properties in the United States. As a non‑operator, we are able to diversify our investment exposure by participating in a large number of gross wells, as well as entering into additional project areas by partnering with numerous experienced operating partners or pursuing value‑enhancing acquisitions. In addition, because we can generally elect to participate on a well‑by‑well basis, we believe we have increased flexibility in the timing and amount of our capital expenditures because we are not burdened with various contractual arrangements with respect to minimum drilling obligations. Further, we are able to avoid exploratory and infrastructure costs incurred by many oil and gas producers.
We seek to create value through strategic acquisitions and partnering with operators who have significant experience in developing and producing hydrocarbons in our core areas. We have more than 40 experienced operating partners that provide technical insights and opportunities for acquisitions. Across these operators, no single operator represented more than 15% of our net producing wells as of December 31, 2020. We had historically focused entirely in the Williston Basin of the United States, in North Dakota and Montana, where substantially all of our assets were located as of December 31, 2020. We expanded our strategy in 2020, making our first small acquisitions in the Permian Basin. In February 2021, we entered into an agreement to acquire producing natural gas properties in the Appalachian Basin from Reliance Marcellus, LLC (the “Reliance Acquisition”), which we anticipate will close in April 2021. See Note 14 to our financial statements for further details regarding the pending Reliance Acquisition.
The following table provides a summary of certain information regarding our assets as of December 31, 2020, including reserves information as estimated by our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc.:
|As of December 31, 2020|
|Productive Wells||Average Daily Production(1)|
(Boe per day)
|% Oil||% Proved Developed|
|Williston Basin||183,242 ||6,633 ||474.5 ||35,583 ||119,523 ||78 ||%||69 ||%|
|Permian Basin||285 ||7 ||0.6 ||155 ||3,109 ||82 ||54 |
|Total||183,527 ||6,640 ||475.1 ||35,738 ||122,632 ||78 ||%||69 ||%|
(1)Represents the average daily production over the three months ended December 31, 2020.
Key elements of our business strategies include:
•Diversify Our Risk Through Non-Operated Participation in a Large Number of Wells and Multiple Basins. As a non-operator, we seek to diversify our investment and operational risk through participation in a large number of oil and gas wells and with multiple operators. As of December 31, 2020, we have participated in 6,640 gross (475.1 net) producing wells with an average working interest of 7.2% in each gross well, with more than 40 experienced operating partners. We believe the best way to develop our acreage is to take a long-term approach and to participate in the development of our locations with potential for the highest rates of return while preserving optionality to allocate capital to assets in our portfolio that offer the highest projected rates of return. We also believe that we can further diversify our risk with acquisitions in other basins, which we began in 2020 in the Permian Basin and expect to continue in 2021, including via the pending Reliance Acquisition.
•Accelerate Growth by Pursuing Value-Enhancing Acquisitions. We strive to be the natural consolidator and clearing house of non-operated working interest in various leading oil and gas shale plays in the United States. Our “ground game” acquisition strategy is to build a strong presence in our core basins and seek to acquire smaller additional lease positions at a significant discount to the contiguous acreage positions typically sought by larger producers and operators of oil and gas wells, focusing on near term drilling opportunities. Such acquisitions have been a significant driver of our net well additions and additions to production. We intend to continue these activities, while at the same time evaluating and pursuing larger non-operated asset packages, such as the pending Reliance Acquisition, that we believe can responsibly accelerate our growth strategy.
•Build and Maintain a Strong Balance Sheet and Proactively Manage to Limit Downside. We strive for financial strength and flexibility through the prudent management of our balance sheet. Additionally, given the volatility of the commodity price environment, we employ an active commodity price risk management program to better enable us to execute our business plan over the entire commodity price cycle.
Industry Operating Environment
The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of taxation, energy, climate change and the environment, political and social developments in the Middle East, demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source.
Oil and natural gas prices have been, and we expect may continue to be, volatile. Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and gas prices may also reduce the amount of our borrowing base under our revolving credit facility, which is determined at the discretion of the lenders based on various factors including the collateral value of our proved reserves. While lower commodity prices may reduce our future net cash flow from operations, we expect to have sufficient liquidity to continue development of our oil and gas properties. In addition, we undertake an active commodity hedging program that is designed to help stabilize the volatile commodity pricing environment and protect cash flows in a potential downturn.
We primarily engage in oil and natural gas exploration and production by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. In addition, we acquire wellbore-only working interests in wells in which we do not hold the underlying leasehold interests from third parties unable or unwilling to participate in particular well proposals. We typically depend on drilling partners to propose, permit and initiate the drilling of wells. Prior to commencing drilling, our partners are required to provide all owners of oil, natural gas and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. We assess each drilling opportunity on a case-by-case basis and participate in wells that we expect to meet our return thresholds based upon our estimates of ultimate recoverable oil and natural gas, expected oil and gas prices, expertise of the operator, and completed well cost from each project, as well as other factors. Historically, we have participated pursuant to our working interest in a vast majority of the wells proposed to us. However, declines in oil prices typically reduce both the number of well proposals we receive and the proportion of well
proposals in which we elect to participate. Our land and engineering team uses our extensive database to make these economic decisions. Given our large acreage footprint and substantial number of well participations, we believe we can make accurate economic drilling decisions.
Historically, we have not managed our commodities marketing activities internally. Instead, our operating partners generally market and sell oil and natural gas produced from wells in which we have an interest. Our operating partners coordinate the transportation of our oil and gas production from our wells to appropriate pipelines or rail transport facilities pursuant to arrangements that they negotiate and maintain with various parties purchasing the production. We understand that our partners generally sell our production to a variety of purchasers at prevailing market prices under separately negotiated short-term contracts. Although we have historically relied on our operating partners for these activities, we may in the future seek to take a portion of our production in kind and internally manage the marketing activities for such production. The price at which production is sold generally is tied to the spot market for oil. Williston Basin Light Sweet Crude from the Bakken source rock is generally 41-42 API crude oil and is readily accepted into the pipeline infrastructure. Our weighted average oil price differential during 2020 was $6.63 per barrel below NYMEX pricing. This differential primarily represents the transportation costs in moving the oil from wellhead to refinery and will fluctuate based on availability of pipeline, rail and other transportation methods. Using our commodity hedging program, we may, from time to time, enter into financial hedging contracts to help mitigate pricing risk and volatility with respect to differentials.
The oil and natural gas industry is intensely competitive and we compete with numerous other oil and natural gas exploration and production companies, many of which have substantially greater resources than we have and may be able to pay more for exploratory prospects and productive oil and natural gas properties. Our larger or integrated competitors may be better able to absorb the burden of existing, and any changes to federal, state, and local laws and regulations than we can, which would adversely affect our competitive position. Our ability to discover reserves and acquire additional properties in the future is dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Marketing and Customers
The market for oil and natural gas that will be produced from our properties depends on many factors, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our operating partners to market and sell our production. Our operating partners include a variety of exploration and production companies, from large publicly-traded companies to small, privately-owned companies. We do not believe the loss of any single operator would have a material adverse effect on our company as a whole.
Title to Properties
Our oil and natural gas properties are subject to customary royalty and other interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. A significant portion of our indebtedness, including under our revolving credit facility and senior secured notes, is also secured by liens 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 title to or rights in our producing properties. As is customary in the oil and gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title only when we acquire producing properties or before commencement of drilling operations.
Winter weather conditions and lease stipulations can limit or temporarily halt the drilling and producing activities of our operating partners and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt the operations of our operating partners and materially increase our operating and capital costs. Such
seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operating partners’ operations.
Principal Agreements Affecting Our Ordinary Business
We do not own any physical real estate, but, instead, our acreage is comprised of leasehold interests subject to the terms and provisions of lease agreements that provide our company the right to participate in drilling and maintenance of wells in specific geographic areas. Lease arrangements that comprise our acreage positions are generally established using industry-standard terms that have been established and used in the oil and natural gas industry for many years. Some of our leases may be acquired from other parties that obtained the original leasehold interest prior to our acquisition of the leasehold interest.
In general, our lease agreements stipulate three-to-five year terms. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production established, the leased acreage in the applicable spacing unit is considered developed acreage and is held by production. Other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production. Given the current pace of drilling in the areas of our operations, we do not believe lease expiration issues will materially affect our acreage position.
Governmental Regulation and Environmental Matters
Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole.
Regulation of Oil and Natural Gas Production
Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota and Montana require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Moreover, the current administration has indicated that it expects to impose additional federal regulations limiting access to and production from federal lands. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.
Regulation of Transportation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. 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 transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index
level in relation to changes in industry costs. On December 17, 2015, the FERC established a new price index for the five-year period which commenced on July 1, 2016.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.
Onshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:
•require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;
•limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and
•impose substantial liabilities for pollution resulting from its operations.
The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general.
The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. Recent regulation and litigation that has been brought against others in the industry under RCRA concern liability for earthquakes that were allegedly caused by injection of oil field wastes.
The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of ESA. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our operating partners) to significant expenses to modify our operations or could force discontinuation of certain operations altogether.
The Clean Air Act (“CAA”) controls air emissions from oil and natural gas production and natural gas processing operations, among other sources. CAA regulations include New Source Performance Standards (“NSPS”) for the oil and natural gas source category to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities.
In recent years, there has been considerable uncertainty surrounding regulation of methane emissions, as the EPA previously published final regulations under the Clean Air Act establishing new performance standards for methane in 2016, but since that time the EPA has undertaken several measures, including issuing rules in 2020, to delay implementation of the methane standards. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA’s 2020 final rule. Notwithstanding the current court challenges, the EPA under the current administration may reconsider the 2020 final rule, which could result in more stringent methane emission rulemaking. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored Paris Agreement, which is a non-binding agreement for nations to limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020. While the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden recommitted the United States to the Paris Agreement on January 20, 2021.
These regulations and proposals and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.
The Federal Water Pollution Control Act of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters and other pollutants into waters of the United States (“WOTUS”). Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. CWA jurisdiction depends on the definition of WOTUS. This definition has been in flux since 2015, when US EPA and the Army Corps of Engineers enacted regulations to more broadly define WOTUS, thereby potentially expanding CWA jurisdiction. The 2015 WOTUS rule is subject to numerous legal challenges, which have left the new definition in place in 26 states but enjoined in 24 states, including Montana and North Dakota. Furthering uncertainty about CWA jurisdiction, in February 2019, US EPA and the Army Corps of Engineers proposed a replacement WOTUS rule circumscribing CWA jurisdiction. This rule will likely also be challenged once it is finally promulgated. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Although the
federal CWA is currently interpreted not to regulate discharges to groundwater, on February 21, 2019, the United States Supreme Court accepted jurisdiction to review the case County of Maui v. Hawaii Wildlife Fund, No. 18-260, which raises the question whether the federal CWA regulates pollutants that originate from a point source but are only conveyed to navigable water through groundwater. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges, for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.
The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Substantially all of the oil and natural gas production in which we have interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act to address hydraulic fracturing operations.
Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts. Several states, including Montana and North Dakota where our properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states, including Colorado and Texas, have enacted bans on hydraulic fracturing. New York State’s ban on hydraulic fracturing was recently upheld by the Courts. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, which could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our revenue and results of operations.
The National Environmental Policy Act (“NEPA”) establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. Many of the activities of our third-party operating partners are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.
Significant studies and research have been devoted to climate change, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production.
In the United States, no comprehensive federal climate change legislation has been implemented to date but the current administration has indicated willingness to pursue new climate change legislation, executive actions or other regulatory initiatives to limit greenhouse gas (“GHG”) emissions. Further, legislative and regulatory initiatives are already underway to that purpose. The U.S. Congress has considered legislation that would control GHG emissions through a “cap and trade” program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the CAA definition of an “air pollutant.” Recent litigation has held that if a source was subject to Prevention of Significant Deterioration (“PSD”) or Title V based on emissions of conventional pollutants like sulfur dioxide, particulates, nitrogen dioxide, carbon monoxide, ozone or lead, then the EPA could also require the source to control GHG emissions and the source would have to install Best Available Control Technology to do so. As a result, a source may still have to control GHG emissions if it is an otherwise regulated source.
In 2014, Colorado was the first state in the nation to adopt rules to control methane emissions from oil and gas facilities. In 2016, the EPA issued three final rules that were intended to curb emissions of methane, VOCs and toxic air pollutants such as benzene from new, reconstructed and modified oil and gas sources. These regulations include leak detection
and repair provisions, and may require controls to reduce methane emissions from certain oil and gas facilities. To the extent that these regulations remain in place and to the extent that our third party operating partners are required to further control methane emissions, such controls could impact our business.
In addition, our third party operating partners are required to report their greenhouse gas emissions under CAA rules. Because regulation of GHG emissions continues to evolve, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover, while the U.S. Supreme Court held in its 2011 decision American Electric Power Co. v. Connecticut that, with respect to claims concerning GHG emissions, the federal common law of nuisance was displaced by the CAA, the Court left open the question of whether tort claims against sources of GHG emissions alleging property damage may proceed under state common law. There thus remains some litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Although operators may take steps to mitigate physical risks from storms, no assurance can be given that future storms will not have a material adverse effect on our business.
Human Capital Resources
As of December 31, 2020, we had 25 full time employees. We may hire additional personnel as appropriate. We also may use the services of independent consultants and contractors to perform various professional services.
Our executive offices are located at 601 Carlson Pkwy, Suite 990, Minnetonka, Minnesota 55305. Our office space consists of 8,295 square feet of leased space. We believe our current office space is sufficient to meet our needs and that additional office space can be obtained if necessary.
On May 9, 2018, we filed articles of conversion with the Secretary of State of the State of Minnesota and filed a certificate of conversion with the Secretary of State of the State of Delaware changing our jurisdiction of incorporation from Minnesota to Delaware (the “Reincorporation”). The Reincorporation was approved by our stockholders at a special meeting held on May 8, 2018. Upon the Reincorporation, each outstanding certificate representing shares of the Minnesota corporation’s common stock was deemed, without any action by the holders thereof, to represent the same number and class of shares of our company’s common stock. As of May 9, 2018, the rights of our stockholders began to be governed by Delaware General Corporation Law and our Delaware certificate of incorporation and bylaws.
Available Information – Reports to Security Holders
Our website address is www.northernoil.com. We make available on this website, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. Electronic filings with the SEC are also available on the SEC internet website at www.sec.gov.
We have also posted to our website our Audit Committee Charter, Compensation Committee Charter, Nominating Committee Charter and our Code of Business Conduct and Ethics, in addition to all pertinent company contact information.
Item 1A. Risk Factors
Risks Related to Our Business and the Oil, Natural Gas and NGL Industry
Our business and operations have been and will likely continue to be adversely affected by the recent COVID-19 pandemic.
The spread of COVID-19 caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economy, including the global and domestic decreased demand for oil and natural gas, which has had an adverse effect on our business, financial condition and results of operations. Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 could also negatively impact the availability of key personnel and adequate staffing for us and our operating partners to conduct business. If COVID-19 continues to spread or the response to contain the COVID-19 pandemic is unsuccessful, we could continue to experience a material adverse effect on our business, financial condition and results of operations.
The duration and extent to which the COVID-19 crisis and oil price volatility adversely affects our business, financial condition and results of operations will depend on future developments, which are highly uncertain and cannot be predicted, including the scope and duration of the pandemic and actions taken by foreign and domestic governmental authorities and other third parties in response. Volatility in commodity prices has had an adverse impact on our financial condition and results of operations, and on the level at which we are able to hedge our anticipated future production, which could continue to materially and adversely affect us, and we cannot predict the ultimate impact of this situation on our business, financial condition and results of operations.
The foregoing has had, and we expect will continue to have, an adverse effect on our business, financial condition, liquidity and results of operations. These factors will likely have the effect of heightening many of the other risks described in this “Risk Factors” section. Without limiting the generality of the foregoing, some impacts of the COVID-19 pandemic and recent oil market developments that could have an adverse effect on our business, financial condition, liquidity and results of operations, include:
•significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;
•further decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of the coronavirus;
•significantly reduced development activity on our properties by operators in the Willison Basin;
•increased likelihood that the operators of our wells will curtail or shut-in production, either voluntarily or as a result of third-party and regulatory mandates, due to depressed oil prices, lack of storage, and/or other market, social, legal, or political forces;
•increased costs associated with, or actual unavailability of, facilities for the storage of oil, gas and NGL production, in the markets in which we operate;
•increased operational difficulties associated with, or an inability to, deliver oil and NGLs to end-markets, resulting from pipeline and storage constraints;
•the potential for loss of leasehold or asset value for failure to produce oil and gas in paying quantities;
•increased third-party credit risk resulting from adverse market conditions, a lack of access to capital and storage, and the failure of certain of our counterparties to continue as going concerns;
•increased costs, either directly or indirectly, related to facility modifications, social distancing measures or other best practices implemented in response to the COVID-19 pandemic and or due to changes in federal, state, and local laws and regulations;
•reducing estimated volumes and value attributable to our proved reserves;
•reducing carrying value of our oil and gas properties due to recognizing impairments on such properties; and
•limiting access to, or increasing the cost of, sources of capital such as equity and long-term debt.
In addition, the COVID-19 pandemic and recent commodity market developments may also affect our business, operations or financial condition in a manner that is not presently known to us or that we currently do not expect to present a significant risk to our business, operations or financial condition.
Oil and natural gas prices are volatile. Extended declines in oil and natural gas prices have adversely affected, and could in the future adversely affect, our business, financial position, results of operations and cash flow.
The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Oil and natural gas prices have fluctuated significantly, including periods of rapid and material decline, in recent years. The prices we receive for our oil and natural gas production heavily influences our production, revenue, cash flows, profitability, reserve bookings and access to capital. Although we seek to mitigate volatility and potential declines in commodity prices through derivative arrangements that hedge a portion of our expected production, this merely seeks to mitigate (not eliminate) these risks, and such activities come with their own risks.
The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
•changes in global supply and demand for oil and natural gas;
•the actions of OPEC and other major oil producing countries;
•worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics (such as the global COVID-19 coronavirus outbreak in early 2020);
•the price and quantity of imports of foreign oil and natural gas;
•political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;
•the level of global oil and natural gas exploration, production activity and inventories;
•changes in U.S. energy policy;
•weather conditions and outbreak of disease;
•technological advances affecting energy consumption;
•domestic and foreign governmental taxes, tariffs and/or regulations;
•proximity and capacity of oil and natural gas pipelines and other transportation facilities;
•the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and
•the price and availability of alternative fuels.
These factors and the volatility of the energy markets make it extremely difficult to predict oil and natural gas prices. A substantial or extended decline in oil or natural gas prices, such as the significant and rapid decline that occurred in 2020, has resulted in and could result in future impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, 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 may be required to reduce spending or borrow or issue additional equity to cover any such shortfall. Lower oil and natural gas prices may limit our ability to comply with the covenants under our revolving credit facility (or other debt instruments) and/or limit our ability to access borrowing availability thereunder, which is dependent on many factors including the value of our proved reserves.
Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.
Our operators’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including:
•declines in oil or natural gas prices, as occurred in 2020 in connection with the COVID-19 pandemic;
•infrastructure limitations, such as the gas gathering and processing constraints experienced in the Williston Basin in 2019;
•the high cost, shortages or delays of equipment, materials and services;
•unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems;
•compliance with environmental and other governmental requirements;
•regulations, restrictions, moratoria and bans on hydraulic fracturing;
•unusual or unexpected geological formations;
•environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;
•fires, blowouts, craterings and explosions;
•uncontrollable flows of oil, natural gas or well fluids; and
•pipeline capacity curtailments.
In addition to causing curtailments, delays and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
Due to declines in oil and natural gas prices, we have taken significant writedowns of our oil and natural gas properties. We may be required to record further writedowns of our oil and natural gas properties.
In 2020, we were required to write down the carrying value of certain of our oil and natural gas properties, and further writedowns could be required in the future. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment would be recognized. Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods.
Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Determining the amount of oil and natural gas recoverable from various formations involves significant complexity and uncertainty. No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating, exploration and development costs. Some of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.
We routinely make estimates of oil and natural gas reserves in connection with managing our business and preparing reports to our lenders and investors. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, development schedules, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, reserve engineers and other advisors to make accurate assumptions. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K, subsequent reports we file with the SEC or other company materials.
Our future success depends on our ability to replace reserves that our operators produce.
Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. We have added significant net wells and production from wellbore-only acquisitions, where we don’t hold the underlying leasehold interest that would entitle us to participate in future wells. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.
We may acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon our initial investments. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive or that we will recover all or any portion of our investments in our properties and reserves.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
We base the estimated discounted future net cash flows from our proved reserves using a specified pricing and cost assumptions. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as the volume, pricing and duration of our oil and natural gas hedging contracts; actual prices we receive for oil, natural gas and NGLs; our actual operating costs in producing oil, natural gas and NGLs; the amount and timing of our capital expenditures; the amount and timing of actual production; and changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.
Our business depends on third party transportation and processing facilities and other assets that are owned by third parties.
The marketability of our oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, physical damage, scheduled maintenance, legal or other reasons such as suspension of service due to legal challenges (see below regarding the Dakota Access Pipeline), could result in a substantial increase in costs, declines in realized commodity prices, the shut-in of producing wells or the delay or discontinuance of development plans for our properties. During 2019 and into 2020, we experienced significant delays and production curtailments, and declines in realized natural gas prices, that we believe were due in part to gas gathering and processing constraints in the Williston Basin. The negative effects arising from these and similar circumstances may last for an extended period of time. In many cases, operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, we rely on third party oil trucking to transport a significant portion of our production to third party transportation pipelines, rail loading facilities and other market access points.
The Dakota Access Pipeline (“DAPL”), a major pipeline running out of the Williston Basin, is subject to ongoing litigation (the “DAPL Litigation”) that could threaten its continued operation. In July 2020, a federal district court ordered DAPL to be shut down no later than August 6, 2020, pending the completion of an environmental impact statement (“EIS”) that is expected to take at least a year to complete. The district court’s shut-down order was subsequently temporarily stayed by a federal circuit court of appeals, and DAPL currently remains operational. However, in January 2021, a federal circuit court of appeals agreed with the federal district court that the government should have conducted an EIS before going forward with the pipeline, and vacated easements granted for its construction to cross beneath Lake Oahe, a reservoir along the Missouri River maintained by the U.S. Army Corps of Engineers (“USACE”). The federal circuit court of appeals did not agree with the lower court’s decision that the pipeline should be shut down, and instead left the decision on how to proceed to the USACE. A shut-down remains possible, and there is no guarantee that DAPL will be permitted to resume or continue operations following the completion of the EIS and/or the DAPL Litigation. Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third party trucking or rail capacity, could adversely affect our business, results of operations and financial condition.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established or operations are commenced on units containing the acreage or the leases are extended.
A significant portion of our acreage is not currently held by production or held by operations. Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related properties. Drilling plans for these areas are generally in the discretion of third party operators and are subject to change
based on various factors that are beyond our control, such as: the availability and cost of capital, equipment, services and personnel; seasonal conditions; regulatory and third party approvals; oil, NGL and natural gas prices; results of title work; gathering system and other transportation constraints; drilling costs and results; and production costs. As of December 31, 2020, we estimate that we had leases that were not developed that represented 4,947 net acres potentially expiring in 2021, 6,923 net acres potentially expiring in 2022, 3,152 net acres potentially expiring in 2023, 1,083 net acres potentially expiring in 2024, and 2,774 net acres potentially expiring in 2025 and beyond.
Seasonal weather conditions adversely affect operators’ ability to conduct drilling activities in the areas where our properties are located.
Seasonal weather conditions can limit drilling and producing activities and other operations in our operating areas and as a result, a majority of the drilling on our properties is generally performed during the summer and fall months. These seasonal constraints can pose challenges for meeting well drilling objectives and increase competition for equipment, supplies and personnel during the summer and fall months, which could lead to shortages and increase costs or delay operations. Additionally, many municipalities impose weight restrictions on the paved roads that lead to jobsites due to the muddy conditions caused by spring thaws. This could limit access to jobsites and operators’ ability to service wells in these areas.
As a non-operator, our development of successful operations relies extensively on third-parties, which could have a material adverse effect on our results of operation.
We have only participated in wells operated by third parties. The success of our business operations depends on the timing of drilling activities and success of our third-party operators. If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.
These risks are heightened in a low commodity price environment, which may present significant challenges to our operators. The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital. Commodity prices and/or other conditions have in the past and may in the future cause oil and gas operators to file for bankruptcy. The insolvency of an operator of any of our properties, the failure of an operator of any of our properties to adequately perform operations or an operator’s breach of applicable agreements could reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner. Finally, an operator of our properties may have the right, if another non-operator fails to pay its share of costs because of its insolvency or otherwise, to require us to pay our proportionate share of the defaulting party’s share of costs.
Our operators will make decisions in connection with their operations (subject to their contractual and legal obligations to other owners of working interests), which may not be in our best interests. We may have no ability to exercise influence over the operational decisions of our operators, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on our operators could prevent us from realizing our target returns for those locations. The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including, oil and natural gas prices and other factors generally affecting industry operating environment; the timing and amount of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of technology; and the rate of production of reserves, if any.
The inability of one or more of our operating partners to meet their obligations to us may adversely affect our financial results.
Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which operating partners market on our behalf to energy marketing companies, refineries and their affiliates. We are subject to credit risk due to the concentration of our oil and natural gas receivables with a limited number of operating partners. This concentration may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. A low commodity price environment may strain our operating partners, which could heighten this risk. The inability or failure of our operating partners to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.
An increase in commodity prices or other factors could result in increased development activity and investment in our areas of operations, which may increase competition for and cost of equipment, labor and supplies. Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict our operating partners’ ability to conduct desired or expected operations. In addition, capital and operating costs in the oil and natural gas industry have generally risen during periods of increasing commodity prices as producers seek to increase production in order to capitalize on higher commodity prices. In situations where cost inflation exceeds commodity price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash flows.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 31% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2020. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.
We intend to expand our operations in part through acquisitions, including without limitation the pending Reliance Acquisition. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not economically feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections are often not performed on properties being acquired, and environmental matters, such as subsurface contamination, are not necessarily observable even when an inspection is undertaken. Any acquisition involves other potential risks, including, among other things:
•the validity of our assumptions about reserves, future production, revenues and costs;
•a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions;
•a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•the ultimate value of any contingent consideration agreed to be paid in an acquisition;
•dilution to shareholders if we use equity as consideration for, or to finance, acquisitions;
•the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
•an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and
•an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
If the Reliance Acquisition is consummated, we may be unable to successfully integrate the Reliance Assets into our business or achieve the anticipated benefits of the Reliance Acquisition.
Our ability to achieve the anticipated benefits of the Reliance Acquisition will depend in part upon whether we can integrate the acquired assets into our existing business in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties requires an assessment of several factors, including:
•future oil and natural gas prices and their appropriate differentials;
•availability and cost of transportation of production to markets;
•availability and cost of drilling equipment and of skilled personnel;
•development and operating costs including access to water and potential environmental and other liabilities; and
•regulatory, permitting and similar matters.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we have performed a review of the subject properties that we believe to be generally consistent with industry practices. The review was based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines without review by an independent petroleum engineering firm. Data used in such review was furnished by the seller or obtained from publicly available sources. Our review may not reveal all existing or potential problems or permit us to fully assess the deficiencies and potential recoverable reserves for all of the acquired properties, and the reserves and production related to the acquired assets may differ materially after such data is further reviewed. Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies. We are often not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities associated with the assets to be acquired in the Reliance Acquisition, we are entitled to indemnification for only certain environmental liabilities. The integration process may be subject to delays or changed circumstances, and we can give no assurance that the acquired assets will perform in accordance with our expectations or that our expectations with respect to integration as a result of the Reliance Acquisition will materialize.
Failure to complete the Reliance Acquisition could negatively impact our future business and financial results.
The consummation of the pending Reliance Acquisition is subject to various customary and other closing conditions, some of which are beyond our control, and we cannot assure you that the Reliance Acquisition will be consummated. If the Reliance Acquisition is not completed or if there are significant delays in completing the Reliance Acquisition, our future business and financial results and the trading price of our common stock could be negatively affected. In particular, there may be negative reactions from the financial markets due to the fact that current prices of our common stock may reflect a market assumption that the Reliance Acquisition will be completed.
The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely could diminish our ability to conduct our operations and harm our ability to execute our business plan.
Our success depends heavily upon the continued contributions of those members of our management team whose knowledge, relationships with industry participants, leadership and technical expertise would be difficult to replace. In particular, our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants. In addition, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment is dependent on our management team’s knowledge and expertise in the industry. To continue to develop our business, we rely on our management team’s knowledge and expertise in the industry and will use our management team’s relationships with industry participants to enter into strategic relationships. The members of our management team may terminate their employment with our company at any time. If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed.
Deficiencies of title to our leased interests could significantly affect our financial condition.
We typically do not incur the expense of a title examination prior to acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights. If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights have been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value or be eliminated. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights may be lost. It is generally our practice not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we typically rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.
Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination. Any one or more of the foregoing could require us to reverse revenues previously recognized and potentially negatively affect our cash flows and results of
operations. Our failure to obtain perfect title to our leaseholds may adversely affect our current production and reserves and our ability in the future to increase production and reserves.
Our lack of industry and geographical diversification may increase the risk of an investment in our company.
We have begun to diversify with the pending Reliance Acquisition in the Appalachian Basin and smaller acquisitions in the Permian Basin, however our operations remain heavily concentrated in primarily oil wells in the Williston Basin. While other companies may have the ability to manage their risk by diversification, the narrow focus of our business, in terms of both the industry focus and geographic scope of our business, means that we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified. As a result of the narrow focus of our business, we may be disproportionately exposed to the effects of regional supply and demand factors, delays or interruptions of production from wells in our areas caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of oil or natural gas. Additionally, we may be exposed to further risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a particular area of operations.
Our derivatives activities could adversely affect our cash flow, results of operations and financial condition.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil and natural gas, we enter into derivative instrument contracts for a portion of our expected production, which may include swaps, collars, puts and other structures. In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our balance sheet as assets or liabilities and in our statements of income as gain (loss) on derivatives, net. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments. In addition, while intended to mitigate the effects of volatile oil and natural gas prices, our derivatives transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which a counterparty to our derivative contracts is unable to satisfy its obligations under the contracts; our production is less than expected; or there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement.
Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.
We may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.
We depend on computer and telecommunications systems, and failures in our systems or cyber security attacks could significantly disrupt our business operations.
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 or may develop proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible that we, or these third parties, could incur interruptions from cyber security 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; 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. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. 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 vendors and service providers.
Risks Related to Our Financing and Indebtedness
Any significant reduction in our borrowing base under our revolving credit facility will negatively impact our liquidity and could adversely affect our business and financial results.
Availability under our revolving credit facility is subject to a borrowing base, with scheduled semiannual (April 1 and October 1) and other elective borrowing base redeterminations based upon, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the revolving credit facility. The lenders under the revolving credit facility can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Reductions in estimates of our producing oil, NGL and natural gas reserves could result in a reduction of our borrowing base thereunder. The same could also arise from other factors, including but not limited to lower commodity prices or production; inability to drill or unfavorable drilling results; changes in crude oil, NGL and natural gas reserve engineering; increased operating and/or capital costs; or other factors affecting our lenders’ ability or willingness to lend (including factors that may be unrelated to our company). Any significant reduction in our borrowing base could result in a default under current and/or future debt instruments, negatively impact our liquidity and our ability to fund our operations and, as a result, could have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess. If we do not have sufficient funds and we are otherwise unable to arrange new financing, we may have to sell significant assets or take other actions to address. Any such sale or other actions could have a material adverse effect on our business and financial results.
Our revolving credit facility and other agreements governing indebtedness contain operating and financial restrictions that may restrict our business and financing activities.
Our revolving credit facility, the indenture governing our senior indebtedness, and any future indebtedness we incur may contain a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things: declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests or purchase or redeem certain debt; make loans or certain investments; make certain acquisitions and investments; incur or guarantee additional indebtedness or issue certain types of equity securities; incur liens; transfer or sell assets; create subsidiaries; consolidate, merge or transfer all or substantially all of our assets; and engage in transactions with our affiliates. In addition, the revolving credit facility requires us to maintain compliance with certain financial covenants and other covenants. As a result of these covenants, we could be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Our ability to comply with some of the covenants and restrictions may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility or any other indebtedness could result in an event of default under our revolving credit facility or our other indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder would not be required to lend any additional amounts to us; could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable; may have the ability to require us to apply all of our available cash to repay these borrowings; and may prevent us from making debt service payments under our other agreements.
An event of default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under other existing or future indebtedness. Conversely, an event of default or an acceleration under any other existing or future indebtedness could result in an event of default and an acceleration under our revolving credit facility. In addition, our obligations under the revolving credit facility are collateralized by perfected liens and security interests on substantially all of our assets and if we default thereunder the lenders could seek to foreclose on our assets.
We may not be able to generate enough cash flow to meet our debt obligations or our obligations related to our preferred stock.
We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service 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, or to permit us to pay dividends on our preferred stock. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt or dividends on our preferred stock. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt; selling assets; reducing or delaying capital investments; or seeking to raise additional capital. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations or pay dividends on our preferred stock. Our inability to generate sufficient cash flow to satisfy our debt obligations or pay dividends on our preferred stock, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.
We currently owe cumulative dividends with respect to our Series A Preferred Stock, which precludes us from paying dividends with respect to our common stock and has certain other potential or actual adverse consequences.
Our Series A Preferred Stock accrues dividends that are payable semi-annually in arrears on May 15 and November 15 of each year, which commenced on May 15, 2020, when, as and if declared by our Board. As of December 31, 2020, no dividends had been declared or paid, and there were approximately $16.3 million of accumulated dividends on the Series A Preferred Stock. Our failure to pay dividends with respect to the Series A Preferred Stock precludes us from paying dividends or making other distributions on our common stock unless all accumulated and unpaid dividends on the Series A Preferred Stock for all preceding dividend periods have been or contemporaneously are declared and paid in full. Additionally, if dividends on the Series A Preferred Stock are in arrears and unpaid for three or more semi-annual dividend periods (whether or not consecutive), the holders of the Series A Preferred Stock will be entitled to elect two additional directors to serve on the Board during the term of such payment arrearage. Since dividends are currently in arrears for two semi-annual dividend periods, this would occur as a result of the next semi-annual dividend period for which dividends are not paid.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.
Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect interest rates under our revolving credit agreement.
LIBOR is a basic rate of interest widely used as a global reference for setting interest rates on loans and payment rates on other financial instruments. Our revolving credit agreement uses LIBOR as the reference rate for Eurodollar denominated borrowings. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if LIBOR will cease to exist at that time, if new methods of calculating LIBOR will be established such that it continues to exist after 2021 or whether different reference rates will develop. It is impossible to predict the effect these developments, any discontinuance, modification or other reforms to LIBOR or the establishment of alternative reference rates may have on LIBOR, other benchmark rates or floating rate debt instruments. Although our revolving credit agreement contains LIBOR alternative provisions and the ability to negotiate an alternative reference rate, new methods of calculating reference rates or other reforms could cause the interest rates under our revolving credit agreement to be materially different than expected, which could have an adverse effect on our business, financial position and results of operations, and our ability to pay dividends on our common stock.
We may be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.
We may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our revolving credit facility, our senior notes and under any future debt agreements. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from
engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.
Our business plan requires significant capital expenditures, which we may be unable to obtain on favorable terms or at all.
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flow from operations, borrowings under our credit facilities, debt issuances, and equity issuances. Cash reserves, cash from operations and borrowings under our revolving credit facility may not be sufficient to fund our continuing operations and business plan and goals. We may require additional capital and we may be unable to obtain such capital if and when required. If our access to capital were limited due to numerous factors, which could include a decrease in operating cash flow due to lower oil and natural gas prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to develop our properties, replace our reserves and pursue our business plan and goals. We may not be able to incur additional debt under our revolving credit facility, issue debt or equity, engage in asset sales or access other methods of financing on acceptable terms or at all. If the amount of capital we are able to raise from financing activities, together with our cash from operations, is not sufficient to satisfy our capital requirements, we may not be able to implement our business plan and may be required to scale back our operations, sell assets at unattractive prices or obtain financing on unattractive terms, any of which could adversely affect our business, results of operations and financial condition.
Risks Related to Legal and Regulatory Matters
The current administration, acting through the executive branch and/or in coordination with Congress, could enact rules and regulations that restrict our ability to acquire federal leases in the future and/or impose more onerous permitting and other costly environmental, health and safety requirements.
President Biden has stated that he intends to issue Executive Orders to permanently protect certain federal lands, establish monuments, restrict new oil and gas permitting on public lands and waters, and modify royalties to account for climate costs. In January 2021, President Biden signed an Executive Order temporarily suspending oil and gas permitting on federal lands and waters. In addition, the current administration has indicated that his administration is likely to pursue more stringent methane pollution limits for new and existing oil and gas operations. These efforts, among others, are intended to support the current administration’s stated goal of addressing climate change. Potential actions of a Democratic-controlled Congress include imposing more restrictive laws and regulations pertaining to permitting, limitations on greenhouse gas emissions, increased requirements for financial assurance and bonding for decommissioning liabilities, and carbon taxes. Any of these administrative or Congressional actions could adversely affect our financial condition and results of operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements.
Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.
We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S. federal income tax purposes. At December 31, 2020, we had an estimated NOL carryforward of approximately $474.5 million for United States federal income tax purposes. In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “IRC”), a corporation that undergoes an “ownership change” can be subject to limitations on the use of its NOLs to offset future taxable income. We underwent an “ownership change” during 2018 and, as a result, the use of our existing NOL carryforwards are subject to limitations under Section 382, which are generally determined by multiplying the value of our stock at the time of the ownership change by the applicable long term tax exempt rate as defined in Section 382. See Note 10 to our financial statements. Future changes in our stock ownership, some of which are outside of our control, could result in an additional ownership change under Section 382 of the IRC.
Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization
period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the Tax Act, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
The enactment of new or increased severance taxes and impact fees on natural gas production could negatively impact the assets we expect to acquire in the Reliance Acquisition.
The tax laws, rules and regulations that affect the operation of the assets that we expect to acquire in the pending Reliance Acquisition are subject to change. For example, Pennsylvania’s governor has in past legislative sessions proposed legislation to impose a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus Shale formation, either in replacement of or in addition to the existing state impact fee. Pennsylvania’s legislature has not thus far advanced any of the governor’s severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative sessions. Any such tax increase or change could adversely impact our earnings, cash flows and financial position as it relates to these assets.
Our business involves the selling and shipping by rail of crude oil, including from the Bakken shale, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.
A portion of our crude oil production is transported to market centers by rail. Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable materials. Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport 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 United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, any derailment of crude oil from the Bakken shale involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.
Our derivative activities expose us to potential regulatory risks.
The Federal Trade Commission (“FTC”), Federal Regulatory Commission (“FERC”) and the Commodities Futures Trading Commission (“CFTC”) have statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to derivative activities that we undertake with respect to oil, natural gas, NGLs, or other energy commodities, we are required to observe the market-related regulations enforced by these agencies. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.
Legislative and regulatory developments could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivatives market and preventing excessive speculation. In one of the rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued in January 2020 (withdrawing previous proposals from 2013 and 2016), proposed rules imposing position limits for certain futures and options contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of derivative transactions are exempt from these limits, provided that such derivative transactions satisfy the CFTC's requirements for certain enumerated “bona fide” derivative transactions. The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns ten percent or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, although CFTC staff has granted relief until August 12, 2022 from various conditions and requirements in the final aggregation rules. These rules may affect both the size of the positions that we may hold and the ability or willingness of counterparties to trade with us, potentially increasing the costs of transactions. Moreover, such changes could
materially reduce our access to derivative opportunities, which could adversely affect revenues or cash flow during periods of low commodity prices.
The CFTC also has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use. If our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions. The ultimate effect of these rules and any additional regulations on our business is uncertain.
The full impact of the Dodd-Frank Act and related regulatory requirements on our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted. In addition, it is possible that the current administration could expand regulation of the over-the-counter derivatives market and the entities that participate in that market through either the Dodd-Frank Act or the enactment of new legislation. Regulations issued under the Dodd-Frank Act (including any further regulations implemented thereunder) and any new legislation also may require certain counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty. Such legislation and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. We maintain an active hedging program related to commodity price risks. Such legislation and regulations could reduce trading positions and the market-making activities of our counterparties. If we reduce our use of derivatives as a result of legislation and regulations or any resulting changes in the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make payments on our debt obligations. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.
Our business is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Our operational interests, as operated by our third-party operating partners, are regulated extensively at the federal, state, tribal and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, our company (either directly or indirectly through our operating partners) could also be liable for personal injuries, property and natural resource damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our business and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
Part of the regulatory environment in which we do business includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our business and limit the quantity of natural gas we may produce and sell. A major risk inherent in the drilling plans in which we participate is the need for our operators to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on the development of our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff.
Environmental risks may adversely affect our business.
All phases of the oil and natural gas business can present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. There is risk of incurring significant environmental costs and liabilities as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to our business, and historical operations and waste disposal practices. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and the imposition of injunctive relief.
Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge, regardless of whether we were responsible for the release or contamination and regardless of whether our operating partners met previous standards in the industry at the time they were conducted. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of operations on our properties. The application of environmental laws to our business may cause us to curtail production or increase the costs of our production, development or exploration activities.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is used extensively by our third-party operating partners. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Any federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply by us or our third-party operating partners could have a material adverse effect on our financial condition and results of operations.
In addition, in response to concerns relating to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities (so-called “induced seismicity”), regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. These developments could result in additional regulation and restrictions on the use of injection wells by our operators to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Until such pending or threatened legislation or regulations are finalized and implemented, it is not possible to estimate their impact on our business.
Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
The adoption of climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the o oil and natural gas we produce.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. Moreover, climate change may be associated with increased volatility in seasonal temperatures, as well as extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Extreme weather conditions can interfere with our production and increase our costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. See “Item 1. Business—Governmental Regulation and Environmental Matters” and “—Climate Change” for a further discussion of the laws and regulations related to greenhouse gases and of climate change.
Risk Related to our Common Stock
Our certificate of incorporation, bylaws, and Delaware state law contain provisions that may have the effect of delaying or preventing a change in control and may adversely affect the market price of our capital stock.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without any further vote or action by our shareholders. The rights of the holders of our common stock will be subject to the rights of the holders of any preferred stock that may be issued in the future. The issuance of preferred stock could delay, deter or prevent a change in control and could adversely affect the voting power or economic value of our shares. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders, including, among others, limitations on the ability of our stockholders to call special meetings, limitations on the ability of our shareholders to act by written consent, and advance notice provisions for shareholders proposals and nominations for elections to the board of directors to be acted upon at meetings of shareholders. Delaware law generally prohibits us from engaging in any business combination with any “interested shareholder,” meaning generally that a shareholder who owns 15% or more of our stock cannot acquire us for a period of three years from the date such shareholder became an interested shareholder, unless various conditions are met.
The availability of shares for sale or other issuance in the future could reduce the market price of our common stock.
Our board of directors has the authority, without action or vote of our stockholders, to issue all or any part of our authorized but unissued shares of common stock, or issue additional shares of preferred stock, which are convertible into shares of common stock. In the future, we may issue securities to raise cash for acquisitions, as consideration in acquisitions, to pay down debt, to fund capital expenditures or general corporate expenses, in connection with the exercise of stock options or to satisfy our obligations under our incentive plans. We may also acquire interests in other companies by using a combination of cash, our preferred stock and our common stock or just our common stock. We may also issue securities, including our preferred stock, that are convertible into, exchangeable for, or that represent the right to receive, our common stock. The occurrence of any of these events or any issuance of common stock upon conversion of our currently outstanding preferred stock may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock.
Investors in our common stock may be required to look solely to stock appreciation for a return on their investment in us.
Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Covenants contained in the instruments governing our indebtedness and the Certificate of Designations for our preferred stock restrict the payment of dividends. Investors may be forced to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.
Item 1B. Unresolved Staff Comments
Item 2. Properties
Estimated Net Proved Reserves
The table below summarizes our estimated net proved reserves at December 31, 2020 and 2019 based on reports prepared by Cawley, Gillespie & Associates, Inc. (“Cawley”), our third-party independent reserve engineers for the years ending December 31, 2020 and 2019. In preparing its reports, Cawley evaluated properties representing all of our proved reserves at December 31, 2020 and 2019 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. Our estimated net proved reserves in the table below do not include probable or possible reserves and do not in any way include or reflect our commodity derivatives.
| ||December 31, 2020||December 31, 2019|
| ||Proved Reserves|
|SEC Proved Reserves:|
|Developed||84,145 ||69 ||%||96,634 ||59 ||%|
|Undeveloped||38,487 ||31 ||66,673 ||41 |
|Total Proved Properties||122,632 ||100 ||%||163,307 ||100 ||%|
(1)The table above values oil and natural gas reserve quantities as of December 31, 2020 assuming constant realized prices of $32.69 per barrel of oil and $1.61 per Mcf of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.
(2)The table above values oil and natural gas reserve quantities as of December 31, 2019 assuming constant realized prices of $50.53 per barrel of oil and $2.12 per Mcf of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.
Estimated net proved reserves at December 31, 2020 were 122,632 MBoe, a 25% decrease from estimated net proved reserves of 163,307 MBoe at December 31, 2019. The decrease was primarily due to a 35% reduction in the SEC-prescribed oil price at year-end 2020 as compared to 2019 and a decrease in development activity. As a result of lower demand caused by the COVID-19 pandemic and the oversupply of crude oil, spot and future prices of crude oil fell to historic lows during the second quarter of 2020, which in turn reduced development activity in the Williston Basin. The decrease in development activity in 2020 led to a 56% reduction in our developmental capital expenditures compared to 2019 as well as a decrease in the number of undeveloped drilling locations reflected in our 2020 proved reserve estimates. The number of proved undeveloped wells included in the reserves was reduced from 107.5 net wells in 2019 to 58.8 net wells in 2020.
The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2020:
SEC Pricing Proved Reserves(1)
| ||Reserve Volumes|
|PDP Properties||53,839 ||97,690 ||70,121 ||57 ||%||$||512,271 ||72 ||%|
|PDNP Properties||11,296 ||16,370 ||14,024 ||12 ||101,271 ||14 |
|PUD Properties||30,890 ||45,581 ||38,487 ||31 ||98,994 ||14 |
|Total||96,025 ||159,641 ||122,632 ||100 ||%||$||712,536 ||100 ||%|
(1)The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2020 based on average prices of $39.57 per barrel of oil and $1.99 per MMbtu of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per MMbtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. The average resulting price used as of December 31, 2020, after adjustment to reflect applicable transportation and quality differentials, was $32.69 per barrel of oil and $1.61 per Mcf of natural gas.
(2)Boe are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.
(3)Pre-tax PV10%, or “PV-10,” may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure. See “Reconciliation of PV-10 to Standardized Measure” below.
The table above assumes prices and costs discounted using an annual discount rate of 10% without future escalation, 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. The information in the table above does not give any effect to or reflect our commodity derivatives.
Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure for proved reserves calculated using SEC pricing. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves or for reserves calculated using prices other than SEC prices. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.
The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2020 to the Standardized Measure of discounted future net cash flows.
SEC Pricing Proved Reserves
|Standardized Measure Reconciliation|
|Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%)||$||712,536 |
Future Income Taxes, Discounted at 10%(1)
|Standardized Measure of Discounted Future Net Cash Flows||$||712,010 |
(1)The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2020, our future income taxes were significantly reduced.
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer estimating the reserves. Further, our actual realized price for our oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.
Additional discussion of our proved reserves is set forth under the heading “Supplemental Oil and Gas Information - Unaudited” to our financial statements included later in this report.
Proved Undeveloped Reserves
At December 31, 2020, we had approximately 38.5 MMBoe of proved undeveloped reserves as compared to 66.7 MMBoe at December 31, 2019. A reconciliation of the change in proved undeveloped reserves during 2020 is as follows:
|Estimated Proved Undeveloped Reserves at 12/31/2019||66.7 |
|Converted to Proved Developed Through Drilling||(10.4)|
|Added from Extensions and Discoveries||5.6 |
|Removed for 5-Year Rule||(2.8)|
|Estimated Proved Undeveloped Reserves at 12/31/2020||38.5 |
Our future development drilling program includes the drilling of approximately 58.8 proven undeveloped net wells before the end of 2025 at an estimated cost of $341.0 million. Our development plan for drilling proved undeveloped wells calls for the drilling of 22.8 net wells during 2021 (includes 13.6 net wells drilled at December 31, 2020, but classified as proved undeveloped due to Cawley’s internal guidelines which require greater than 50% of total costs to be incurred to be classified as developed), 13.3 net wells during 2022, 10.5 net wells during 2023 and 12.2 net wells during 2024 for a total of 58.8 net wells. Our proved undeveloped locations were reduced from 107.5 net wells at December 31, 2019 to 58.8 net wells at December 31, 2020 due to lower commodity prices and reduced development activity. We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled including our acreage. All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our development plan.
At December 31, 2020, the PV-10 value of our proved undeveloped reserves amounted to 14% of the PV-10 value of our total proved reserves. Although our 2020 producing property additions exceeded our 5-year average development plan, there are numerous uncertainties. The development of these reserves is dependent upon a number of factors which include, but are not limited to: financial targets such as drilling within cash flow or reducing debt, drilling of obligatory wells, satisfactory rates of return on proposed drilling projects, and the levels of drilling activities by operators in areas where we hold leasehold interests. During 2020, we decreased our development capital spending by 56% compared to 2019. With 72% of the PV-10
value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan.
At December 31, 2020, we had spent a total of $69.9 million related to the development of proved undeveloped reserves, which resulted in the conversion of 10.4 MMBoe of proved undeveloped reserves as of December 31, 2019 to proved developed reserves as of December 31, 2020. Proved developed property additions in 2020 also included 2.8 MMBoe from the conversion of previously undeveloped locations that were not booked in our December 31, 2019 proved undeveloped reserves (the related development costs incurred at December 31, 2020 were $28.3 million). Additionally, our proved undeveloped reserves at December 31, 2020 included 8.2 MMBoe for net wells that had commenced drilling activities but remained classified as undeveloped reserves due to Cawley’s internal guidelines which require greater than 50% of the total costs to have been incurred in order to be classified as proved developed (the related development costs incurred at December 31, 2020 were $20.5 million).
In 2020, we also added 5.6 MMBoe of proved undeveloped reserves as a result of our acquisition and development activity. The SEC-prescribed commodity prices (after adjustment for transportation, quality and basis differentials) were $17.84 lower per barrel of oil and $0.51 lower per Mcf of natural gas at year-end 2020 as compared to year-end 2019. Additionally, we had negative revisions of 20.6 MMBoe primarily due to the aforementioned lower pricing. We also removed 2.8 MMBoe of proved undeveloped reserves due to the SEC-prescribed 5-year rule.
Proved Reserves Sensitivity by Price Scenario
The SEC disclosure rules allow for optional reserves sensitivity analysis, such as the sensitivity that oil and natural gas reserves have to price fluctuations. We have chosen to compare our proved reserves from the 2020 SEC case to two alternate pricing cases. The first alternate scenario uses a flat pricing deck of $50.00 per Bbl for oil and $2.50 per MMbtu for natural gas (the “$50 Flat Case”). The second alternate scenario uses a flat pricing deck of $60.00 per Bbl for oil and $2.50 per MMbtu for natural gas (the “$60 Flat Case”). The sensitivity scenarios were not audited by a third party. In these sensitivity scenarios, all operating cost assumptions and other factors, other than the commodity price assumptions, have been held constant with the SEC case. However, the higher pricing in the sensitivity scenarios did result in additional future drilling locations that became economic under the $50 Flat Case and the $60 Flat Case, while they were not economic under the 2020 SEC case. As a result, the $50 Flat Case and the $60 Flat Case included an additional 24.4 and 44.6 proved undeveloped net wells, respectively, compared to the 58.8 proved undeveloped net wells included in the 2020 SEC case. These sensitivities are only meant to demonstrate the impact that changing commodity prices may have on estimated proved reserves and PV-10 and there is no assurance these outcomes will be realized. The table below shows our proved reserves utilizing the 2020 SEC case compared with the two alternate price scenarios.
| ||Price Cases|
$50 Flat Case(2)
$60 Flat Case(3)
|Net Proved Reserves (December 31, 2020)|
|Developed||65,135 ||73,399 ||77,870 |
|Undeveloped||30,890 ||42,648 ||50,781 |
|Total||96,025 ||116,047 ||128,651 |
|Natural Gas (MMcf)|
|Developed||114,060 ||130,604 ||138,852 |
|Undeveloped||45,581 ||60,228 ||68,993 |
|Total||159,641 ||190,832 ||207,846 |
|Total Proved Reserves (MBOE)||122,632 ||147,852 ||163,292 |
Pre-tax PV10% (in thousands)(4)
|$||712,536 ||$||1,329,389 ||$||1,931,094 |
(1)Represents reserves based on pricing prescribed by the SEC. The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $32.69 per Bbl for oil and $1.61 per Mcf for natural gas. Production costs were held constant for the life of the wells.
(2)Prices based on $50.00 per Bbl for oil and $2.50 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $43.06 per Bbl for oil and $2.00 per Mcf for natural gas.
(3)Prices based on $60.00 per Bbl for oil and $2.50 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $53.04 per Bbl for oil and $1.84 per Mcf for natural gas.
(4)Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure. See “Reconciliation of PV-10 to Standardized Measure” above for a reconciliation of the PV-10 of our SEC Case proved reserves to the Standardized Measure. GAAP does not prescribe a corresponding measure for PV-10 of proved reserves based on other than SEC prices. As a result, it is not practicable for us to reconcile the PV-10 of our proved reserves based on the alternate pricing scenarios.
Independent Petroleum Engineers
We have utilized Cawley, an independent reserve engineering firm, as our third-party engineering firm. The selection of Cawley was approved by our Audit Committee. Cawley is a reservoir-evaluation consulting firm who evaluates oil and natural gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States. Cawley has substantial experience calculating the reserves of various other companies with operations targeting the Bakken and Three Forks formations and, as such, we believe Cawley has sufficient experience to appropriately determine our reserves. Cawley utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience. The reports of our estimated proved reserves in their entirety are based on the information we provide to them. Cawley is a Texas Registered Engineering Firm (F-693). Our primary contact at Cawley is Todd Brooker, President. Mr. Brooker is a State of Texas Licensed Professional Engineer (License #83462). He is also a member of the Society of Petroleum Engineers.
In accordance with applicable requirements of the SEC, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).
The reserves set forth in the Cawley report for the properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy. The estimates of the reserves, future production, and income attributable to properties are prepared using the economic software package Aries for Windows, a copyrighted program of Halliburton.
To estimate economically recoverable oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic productivity from a reservoir is to be determined as of the effective date of the report. With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.
The reserve data set forth in the Cawley report represents only estimates, and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves, included in our SEC filings, have not been filed with or included in reports to any other federal agency. See “Item 1A. Risk Factors – Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”
Internal Controls Over Reserves Estimation Process
We utilize a third-party reservoir engineering firm, as our independent reserves evaluator for 100% of our reserves base. In addition, we employ an internal reserve engineering department which is led by our Senior Vice President of Engineering, who is responsible for overseeing the preparation of our reserves estimates. Our senior internal reserve engineer has a B.S. in petroleum engineering from Montana Tech, has over fifteen years of oil and gas experience on the reservoir side, and has experience working for large independent and financial firms on projects and acquisitions.
Our technical team meets with our independent third-party engineering firm to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following:
•Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database;
•Review of working interests and net revenue interests in our reserves database against our well ownership system;
•Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database;
•Review of updated capital costs prepared by our operations team;
•Review of internal reserve estimates by well and by area by our internal reservoir engineer;
•Discussion of material reserve variances among our internal reservoir engineer and our executive management; and
•Review of a preliminary copy of the reserve report by executive management.
Production, Price and Production Expense History
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Oil supply in the United States has grown dramatically over the past few years, and the supply of oil could impact oil prices in the United States if the supply outstrips domestic demand. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.
The following table sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated. For additional information on price calculations, please see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
| ||Years Ended December 31,|
|Oil (Bbl)||9,361,138 ||11,325,418 ||7,790,182 |
|Natural Gas and NGLs (Mcf)||16,473,287 ||16,590,774 ||9,224,766 |
|Total (Boe)||12,106,686 ||14,090,547 ||9,327,643 |
|Average Sales Prices:|| || |
|Oil (per Bbl)||$||32.61 ||$||50.74 ||$||57.78 |
|Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)||20.08 ||3.92 ||(2.94)|
|Oil Net of Settled Oil Derivatives (per Bbl)||52.69 ||54.66 ||54.84 |
|Natural Gas and NGLs (per Mcf)||1.14 ||1.60 ||4.74 |
|Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf)||0.02 ||— ||— |
|Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf)||1.16 ||1.60 ||4.74 |
|Realized Price on a Boe Basis Excluding Settled Commodity Derivatives||26.77 ||42.67 ||52.95 |
|Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)||15.55 ||3.15 ||(2.45)|
|Realized Price on a Boe Basis Including Settled Commodity Derivatives ||42.32 ||45.82 ||50.50 |
|Production Expenses (per Boe)||$||9.61 ||$||8.44 ||$||7.15 |
Drilling and Development Activity
The following table sets forth the number of gross and net productive and non-productive wells drilled in the years ended December 31, 2020, 2019 and 2018. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.
| ||December 31,|
|Oil||— ||— ||— ||— ||— ||— |
|Natural Gas||— ||— ||— ||— ||— ||— |
|Non-Productive||— ||— ||— ||— ||— ||— |
|Development Wells:|| || || || || || |
|Oil||285 ||17.8 ||615 ||43.0 ||505 ||31.2 |
|Natural Gas||— ||— ||— ||— ||— ||— |
|Non-Productive||— ||— ||— ||— ||— ||— |
|Total Productive Exploratory and Development Wells||285 ||17.8 ||615 ||43.0 ||505 ||31.2 |
(1)Net Well totals in 2020, 2019 and 2018 do not include an additional 1.0, 90.1 and 65.8 net wells, respectively, from acquisitions which were already producing when acquired.
The following table summarizes our cumulative gross and net productive oil wells by geographic area within the United States at each of December 31, 2020, 2019 and 2018.
| ||December 31,|
|Williston Basin||6,633 ||474.5 ||6,156 ||458.7 ||4,792 ||325.1 |
|Permian Basin||7 ||0.6 ||— ||— ||— ||— |
|Total||6,640 ||475.1 ||6,156 ||458.7 ||4,792 ||325.1 |
As of December 31, 2020, we had an additional 375 gross (28.1 net) wells in process, meaning wells that have been spud and are in the process of drilling, completing or waiting on completion.
As of December 31, 2020, our principal assets included approximately 183,527 net acres located in the United States. The following table summarizes our estimated gross and net developed and undeveloped acreage by geographic area at December 31, 2020.
| ||Developed Acreage||Undeveloped Acreage||Total Acreage|
As of December 31, 2020, approximately 90% of our total acreage was developed. All of our proved reserves are located in the United States.
We generally assess acreage subject to near-term drilling activities on a lease-by-lease basis because we believe each lease’s contribution to a subject spacing unit is best assessed on that basis if development timing is sufficiently clear. Consistent with that approach, a significant portion of our acreage acquisitions involve properties that are selected by us on a lease-by-lease basis for their participation in a well expected to be spud in the near future, and the subject leases are then aggregated to complete one single closing with the transferor. As such, we generally view each acreage assignment from brokers, landmen and other parties as involving several separate acquisitions combined into one closing with the common transferor for convenience. However, in certain instances an acquisition may involve a larger number of leases presented by the transferors as a single package without negotiation on a lease-by-lease basis. In those instances, we still review each lease on a lease-by-lease basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations. See Note 3 to our financial statements regarding our recent acquisition activity.
As a non-operator, we are subject to lease expirations if an operator does not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage summarized in the table below will expire at the end of their respective primary terms, unless we renew the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised. In addition, our leases typically provide that the lease does not expire at the end of the primary term if drilling operations have been commenced. While we generally expect to establish production from most of our acreage prior to expiration of the applicable lease terms, there can be no guarantee we can do so. The approximate expiration of our net acres which are subject to expire between 2021 and 2025 and thereafter, are set forth below:
| ||Acreage Subject to Expiration|
|December 31, 2021||19,124||4,947|
|December 31, 2022||12,294||6,923|
|December 31, 2023||4,957||3,152|
|December 31, 2024||1,280||1,083|
|December 31, 2025 and thereafter||3,886||2,774|
During 2020, we had leases expire covering approximately 1,720 net acres. The 2020 lease expirations carried a cost of $2.9 million. We believe that the expired acreage was not material to our capital deployed.
All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion.
We assess all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization.
We historically have acquired our properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases generally have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. We generally participate in drilling activities on a proportionate basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.
We believe that the majority of our unproved costs will become subject to depletion within the next five years by proving up reserves relating to its acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of our reserves.
Depletion of Oil and Natural Gas Properties
Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses during 2020, 2019 and 2018.
| ||Years Ended December 31,|
|(In thousands, except per Boe data)||2020||2019||2018|
|Depletion of Oil and Natural Gas Properties||$||160,643 ||$||209,050 ||$||118,974 |
|Depletion Expense (per Boe)||13.27 ||14.84 ||12.75 |
Research and Development
We do not anticipate performing any significant research and development under our plan of operation.
We do not currently have any delivery commitments for product obtained from our wells.
Item 3. Legal Proceedings
Our company is subject from time to time to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.
Item 4. Mine Safety Disclosures
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock trades on the NYSE American under the symbol “NOG.” The closing price for our common stock on the NYSE American on March 11, 2021 was $14.31 per share.
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 the 60-month cumulative total shareholder return on our common stock since December 31, 2015, and the cumulative total returns of Standard & Poor’s Composite 500 Index and the NYSE Arca Oil Index (formerly the AMEX Oil Index) for the same period. This graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends) from December 31, 2015 to December 31, 2020.
* The following table sets forth the total returns utilized to generate the foregoing graph.
|Northern Oil & Gas, Inc.||100.00 ||71.24 ||53.11 ||58.55 ||60.62 ||22.69 |
|S&P 500||100.00 ||111.96 ||136.40 ||130.42 ||171.49 ||203.04 |
|NYSE Arca Oil Index||100.00 ||124.78 ||138.79 ||128.81 ||141.12 ||96.55 |
The stock price performance included in this graph is not necessarily indicative of future stock price performance.
As of March 9, 2021, we had 60,421,200 shares of our common stock outstanding, held by approximately 231 stockholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
Recent Sales of Unregistered Securities
None, except to the extent previously included by the Company in a Quarterly Report on Form 10-Q or Current Report on Form 8-K.
Issuer Purchases of Equity Securities
The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of our common stock during the quarter ended December 31, 2020.
|Period||Total Number of Shares Purchased(1)||Average Price Paid Per Share||Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs||Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(2)|
|Month #1|| |
|October 1, 2020 to October 31, 2020||— ||$||— ||— ||$ 68.1 million|
|Month #2|| || || || |
|November 1, 2020 to November 30, 2020||4,720 ||5.64 ||— ||68.1 million|
|Month #3|| || || || |
|December 1, 2020 to December 31, 2020||830 ||9.12 ||— ||68.1 million|
|Total||5,550 ||$||6.16 ||— ||$ 68.1 million|
(1)The 5,550 total shares purchased outside of publicly announced plans or programs represent shares surrendered in satisfaction of tax withholding obligations in connection with the vesting of restricted stock awards.
(2)In May 2011, our board of directors approved a stock repurchase program to acquire up to $150 million worth of shares of our Company’s outstanding common stock.
Item 6. [RESERVED]
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with our financial statements and accompanying notes to financial statements appearing elsewhere in this report.
Our primary strategy is to invest in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we participated in 6,640 gross (475.1 net) producing wells as of December 31, 2020. As of December 31, 2020, we had leased approximately 183,527 net acres, of which approximately 90% were developed and substantially all were located in the Williston Basin in the United States.
Our average daily production for full year 2020 was 33,078 Boe per day, and in the fourth quarter of 2020 was 35,738 Boe per day (approximately 76% oil). During 2020, we added 17.8 net wells to production, and we ended 2020 with 28.1 net wells in process.
Our financial and operating performance for the year ended December 31, 2020 included the following:
•Oil and gas sales of $324.1 million in 2020, plus an additional $188.3 million of cash settlements on commodity derivatives during 2020
•Cash flows from operations of $331.7 million in 2020
•Proved reserves of 122.6 MMBoe at December 31, 2020, as estimated by our third-party reserve engineers under SEC guidelines
Impacts of COVID-19 Pandemic and Economic Environment
The novel coronavirus disease (COVID-19) and efforts to mitigate the spread of the disease have created unprecedented challenges for our industry, including a drastic decline in demand for crude oil. In addition, in March 2020, members of OPEC failed to agree on production levels which led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended in April 2020, with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. As a result of lower demand caused by the COVID-19 pandemic and the oversupply of crude oil, spot and future prices of crude oil fell to historic lows during the second quarter of 2020 and remained depressed through much of 2020. Operators in the Williston Basin responded by significantly decreasing drilling and completion activity, and by shutting in or curtailing production from a significant number of producing wells.
As a result of these factors, we reduced our 2020 developmental capital spending to $162.8 million, a reduction of 56% compared to our developmental capital expenditures in 2019. Our 2020 production was significantly lower than originally expected due to actions by many of our operating partners to shut-in or curtail production and defer development plans as a result of the low commodity price environment. We estimate that curtailments, shut-ins and delayed well completions reduced our average daily production by approximately 16,800 Boe per day in the second quarter of 2020 and by approximately 11,000 Boe per day in the third quarter of 2020. We estimate that curtailments and shut-ins reduced our average daily production by approximately 4,200 Boe per day in the fourth quarter of 2020. Conditions have improved with the recovery of commodity prices in late 2020 and early 2021, but operators’ decisions on these matters are evolving rapidly, and it remains difficult to predict the future effects on our company and its business. However, we expect that our cash flow from operations and borrowing availability under our revolving credit facility will allow us to meet our liquidity needs for at least the next twelve 12 months.
As a result of low commodity prices during 2020, we incurred a full-cost ceiling test impairment charge of $1,066.7 million for the year ended December 31, 2020. Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Any ceiling test impairment charge would be non-cash in nature and should not impact any covenants under our various debt instruments.
In response to the COVID-19 pandemic, we have instituted various measures to protect our workforce and our business operations, such as remote working and business travel restrictions. As a non-operator with no field operations, substantially all of our employees’ work can be completed from home. We will continue to monitor the guidelines and recommendations provided by the relevant authorities, and we will continue to make decisions aimed at protecting and furthering the interests of all stakeholders.
Reverse Stock Split
On September 18, 2020, we effected a 1-for-10 reverse stock split of the Company’s issued and outstanding shares of common stock (the “Reverse Stock Split”). References to numbers of shares of common stock and per share data have been adjusted to reflect the Reverse Stock Split on a retroactive basis. See Note 5 to our financial statements for further information.
Source of Our Revenues
We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
Principal Components of Our Cost Structure
•Oil price differentials. The price differential between our well head price and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries.
•Gain (loss) on commodity derivatives, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.
•Production expenses. Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.
•Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.
•Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations.
•General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.
•Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our full cost pool. We include interest expense that is not capitalized into the full cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense.
•Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment expense or non-cash writedown is required.
•Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Selected Factors That Affect Our Operating Results
Our revenues, cash flows from operations and future growth depend substantially upon:
•the timing and success of drilling and production activities by our operating partners;
•the prices and the supply and demand for oil, natural gas and NGLs;
•the quantity of oil and natural gas production from the wells in which we participate;
•changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil;
•our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and
•the level of our operating expenses.
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston Basin subjects our operating results to factors specific to this region. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, and the limitations of the developing infrastructure and transportation capacity in this region.
The price of oil in the Williston Basin can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market. Light sweet crude from the Williston Basin has a higher value at many major refining centers because of its higher quality relative to heavier and sour grades of oil; however, because of the Williston Basin’s location relative to traditional oil transport centers, this higher value is generally offset to some extent by higher transportation costs. While rail transportation has historically been more expensive than pipeline transportation, Williston Basin’s prices have at times justified shipment by rail to markets across the United States. Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region, specifically the Dakota Access Pipeline (“DAPL”) which has given the region low-cost transportation with access to Gulf Coast markets, which generally have higher benchmark pricing than WTI prices, offsetting some of the additional cost for the mode and increased distance of transportation.
The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the NYMEX and the sales prices we receive for our oil production. Our oil price differential to the NYMEX benchmark price during 2020 was $6.63 per barrel, as compared to $6.28 per barrel in 2019. Fluctuations in our oil price differential are due to several factors such as takeaway capacity relative to production levels in the Williston Basin, regional storage capacity, and seasonal refinery maintenance temporarily depressing crude demand.
As described in “Item 1A. Risk Factors,” DAPL is subject to ongoing litigation and regulatory review that could threaten its continued operation. During any period that DAPL is forced to shut down, we would expect our average oil price differential to increase, although it is difficult to predict with any precision what effect this would have.
Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in oil prices that can substantially impact the level of drilling activity in the Williston Basin. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant. During 2020, the weighted average authorization for expenditure (or AFE) cost for wells we elected to participate in was $7.5 million, compared to $8.0 million for the wells we elected to participate in during 2019.
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Being primarily an oil producer, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.
During the first half of 2020, the oil and natural gas industry witnessed an abrupt and significant decline in oil prices from $63.00 per Bbl in early January to an average of $27.95 per Bbl during the second quarter of 2020. This sudden decline in oil prices was attributable to two primary factors: (1) the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 and (2) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets following the failure of efforts by members of OPEC+ to agree on coordinated production cuts in March 2020. The OPEC price war ended in April 2020, with a deal to cut global petroleum output but did not go far enough to offset the dramatic negative impact of COVID-19 on demand. Oil prices improved since the second quarter of 2020, but the general outlook for commodity prices and the oil and natural gas industry remains uncertain, and we anticipate ongoing volatility.
Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2020, 2019 and 2018.
| ||December 31,|
Average NYMEX Prices(1)
|Oil (per Bbl)||$||39.24 ||$||57.02 ||$||64.95 |
|Natural Gas (per Mcf)||2.01 ||2.56 ||3.16 |
(1)Based on average NYMEX closing prices.
The average 2020 NYMEX pricing was $39.24 per barrel of oil or 31% lower than the average NYMEX price per barrel in 2019, which was partially offset by a $16.16 per barrel of oil increase in settled derivatives in 2020 as compared to 2019. Our average 2020 realized oil price per barrel after reflecting settled derivatives was $52.69 compared to $54.66 in 2019. Our 2020 realized gas price per Mcf was $1.14 compared to $1.60 in 2019, which was primarily driven by lower NYMEX pricing for both natural gas and natural gas liquids gas gathering as well as processing constraints in the Williston Basin. Recent construction projects have greatly expanded processing capacity within the basin as well as a significant new natural gas liquids pipeline. However, continued expansion of gathering systems in our basin will likely be required to fully harness these new systems and to improve long-term pricing realizations.
We employ a hedging program that mitigates the risk associated with fluctuations in commodity prices. The following tables reflect the weighted average price of open commodity price swap derivative contracts as of December 31, 2020, by year with associated volumes.
|Weighted Average Price|
of Open Oil Swap Contracts
Average Price ($)
|7,545,124 ||55.06 |
|816,250 ||50.49 |
(1)We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 3.1 million barrels for 2022 are exercisable on or about December 31, 2021. If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase by 3.1 million barrels at a weighted average price of $52.68 per barrel for 2022.
(2)We have entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for additional periods. Options covering a notional volume of 1.5 million barrels for 2023 are exercisable on or about December 31, 2022. If the counterparties exercise all such options, the notional volume of our existing crude oil derivative contracts will increase by 1.5 million barrels at a weighted average price of $47.98 per barrel for 2023.
From time to time, we also hedge our oil basis differential to mitigate price risk associated with fluctuations in takeaway capacity. As of December 31, 2020, we have hedged approximately 1.5 million barrels for 2021 at a weighted average price of $(2.39) per barrel. See Note 12 to our financial statements.
|Weighted Average Price|
of Open Natural Gas Swap Contracts
Average Price ($)
|2021||13,000,000 ||2.50 |
|2022||3,650,000 ||2.61 |
Results of Operations for 2020, 2019 and 2018
The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
| ||Years Ended December 31,|
|Oil (Bbl)||9,361,138 ||11,325,418 ||7,790,182 |
|Natural Gas and NGLs (Mcf)||16,473,287 ||16,590,774 ||9,224,766 |
|Total (Boe)||12,106,686 ||14,090,547 ||9,327,643 |
|Net Sales (in thousands):|| || |
|Oil Sales||$||305,249 ||$||574,616 ||$||450,149 |
|Natural Gas and NGL Sales||18,802 ||26,601 ||43,760 |
|Gain (Loss) on Settled Commodity Derivatives||188,264 ||44,377 ||(22,886)|
|Gain (Loss) on Unsettled Commodity Derivatives||39,878 ||(173,214)||207,892 |
|Other Revenue||17 ||21 ||9 |
|Total Revenues||552,210 ||472,402 ||678,924 |
|Average Sales Prices:|| || |
|Oil (per Bbl)||$||32.61 ||$||50.74 ||$||57.78 |
|Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)||20.08 ||3.92 ||(2.94)|
|Oil Net of Settled Oil Derivatives (per Bbl)||52.69 ||54.66 ||54.84 |
|Natural Gas and NGLs (per Mcf)||1.14 ||1.60 ||4.74 |
|Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf)||0.02 ||— ||— |
|Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf)||1.16 ||1.60 ||4.74 |
|Realized Price on a Boe Basis Excluding Settled Commodity Derivatives||26.77 ||42.67 ||52.95 |
|Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)||15.55 ||3.15 ||(2.45)|
|Realized Price on a Boe Basis Including Settled Commodity Derivatives ||42.32 ||45.82 ||50.50 |
|Operating Expenses (in thousands):|| || |
|Production Expenses||$||116,336 ||$||118,899 ||$||66,646 |
|Production Taxes||29,783 ||57,771 ||45,302 |
|General and Administrative Expenses||18,546 ||23,624 ||14,568 |
|Depletion, Depreciation, Amortization and Accretion||162,120 ||210,201 ||119,780 |
|Costs and Expenses (per Boe):|| || |
|Production Expenses||$||9.61 ||$||8.44 ||$||7.15 |
|Production Taxes||2.46 ||4.10 ||4.86 |
|General and Administrative Expenses||1.53 ||1.68 ||1.56 |
|Depletion, Depreciation, Amortization and Accretion||13.39 ||14.92 ||12.84 |
|Net Producing Wells at Period-End||475.1 ||458.7 ||325.1 |
Oil and Natural Gas Sales
Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. In 2020, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased 46% from 2019, driven by a 14% decrease in production volumes coupled with a 37% decrease in realized prices, excluding the effect of settled commodity derivatives. The lower average realized price in 2020 as compared to 2019 was principally driven by lower average NYMEX oil and natural gas prices. The lower NYMEX oil prices were also affected by a higher average oil price differential in 2020 as compared to 2019. The oil price differential during 2020 averaged $6.63 per barrel, as compared to $6.28 per barrel in 2019.
In 2019, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 22% from 2018, driven primarily by a 51% increase in production levels offset by a 19% decrease in realized price, excluding the effect of settled derivatives. The lower average realized price in 2019 as compared to 2018 was principally driven by lower average NYMEX oil and natural gas prices, and gas gathering and processing constraints in the Williston Basin that lowered realized gas prices. The lower NYMEX oil prices were partially offset by a lower average oil price differential in 2019 as compared to 2018. The oil price differential during 2019 averaged $6.28 per barrel, as compared to $7.12 per barrel in 2018.
We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Our acquisition program is a significant driver of our net well additions in certain years. Curtailments, shut-ins and completion delays due to the significant decline in commodity prices drove our 14% decrease in production levels in 2020 as compared to 2019, more than offsetting additions from acquisitions and new wells brought online. See “Impacts of COVID-19 Pandemic and Economic Environment” above. During 2019, our substantial acquisition activities (see Note 3 to our financial statements) combined with increased development activity and improved performance from enhanced completion techniques helped drive an increase in production levels as compared to 2018. In 2019, the number of net wells we added to production (excluding acquisitions) increased by 38% as compared to 2018. The higher number of new well completions and per well productivity improvements drove the 51% increase in production as compared to 2018. Our production for each of the last three years is set forth in the following table:
| ||Year Ended December 31,|
|Oil (Bbl)||9,361,138 ||11,325,418 ||7,790,182 |
|Natural Gas and NGL (Mcf)||16,473,287 ||16,590,774 ||9,224,766 |
|12,106,686 ||14,090,547 ||9,327,643 |
|Average Daily Production:|| || |
|Oil (Bbl)||25,577 ||31,029 ||21,343 |
|Natural Gas and NGL (Mcf)||45,009 ||45,454 ||25,273 |
|33,078 ||38,604 ||25,555 |
(1)Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
Commodity Derivative Instruments
We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our gain (loss) on commodity derivatives, net was a gain of $228.1 million in 2020, compared to a loss of $128.8 million in 2019, and a gain of $185.0 million in 2018. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.
For 2020, we realized a gain on settled commodity derivatives of $188.3 million, compared to a $44.4 million gain in 2019 and a $22.9 million loss in 2018. The percentage of oil production hedged under our derivative contracts was 104%, 76%, and 64% in 2020, 2019, and 2018, respectively. The weighted average oil price on our settled commodity derivative contracts
in 2020, 2019, and 2018 was $58.04, $61.51, and $59.27, respectively. Our average realized price (including all commodity derivative cash settlements) in 2020 was $42.32 per Boe compared to $45.82 per Boe in 2019, and $50.50 per Boe in 2018. The gain (loss) on settled commodity derivatives increased our average realized price per Boe by $15.55 in 2020, increased our average realized price per Boe by $3.15 in 2019 and decreased our average realized price per Boe by $2.45 in 2018.
Unsettled commodity derivative gains and losses was a gain of $39.9 million in 2020 compared to a loss of $173.2 million in 2019 and a gain of $207.9 million in 2018. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At December 31, 2020, all of our derivative contracts are recorded at their fair value, which was a net asset of $33.7 million, an increase of $38.9 million from the $5.2 million net liability recorded as of December 31, 2019. The increase in the net asset at December 31, 2020 as compared to December 31, 2019 was primarily due to changes in forward oil prices relative to prices on our open oil derivative contracts since December 31, 2019. Our open oil derivative contracts are summarized in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Production expenses were $116.3 million in 2020 compared to $118.9 million in 2019 and $66.6 million in 2018. On a per unit basis, production expenses increased 14% from $8.44 per Boe in 2019 to $9.61 per Boe in 2020 due primarily to fixed costs related to shut-in and/or curtailed production as well as higher per unit costs for processing. On an absolute dollar basis, the 2% decrease in our production expenses in 2020 compared to 2019 was primarily due to a 14% decrease in production offset by a 14% increase in per unit costs. On a per unit basis, our production expenses increased from $7.15 per Boe in 2018 to $8.44 per Boe in 2019 due primarily to fixed costs related to shut-in and/or curtailed production as well as higher per unit costs for processing and saltwater disposal charges. On an absolute dollar basis, our production expenses in 2019 were 78% higher when compared to 2018 due primarily to a 51% increase in production and the 18% increase in per unit costs.
We pay production taxes based on realized oil and natural gas sales. Production taxes were $29.8 million in 2020 compared to $57.8 million in 2019 and $45.3 million in 2018. As a percentage of oil and natural gas sales, our production taxes were 9.2%, 9.6% and 9.2% in 2020, 2019 and 2018, respectively. The fluctuation in our average production tax rate from year to year is primarily due to changes in our oil sales as a percentage of our total oil and gas sales. Oil sales are taxed at a higher rate than gas sales.
General and Administrative Expenses
General and administrative expenses were $18.5 million for 2020 compared to $23.6 million for 2019 and $14.6 million for 2018. The decrease in 2020 compared to 2019 was primarily due to a $4.1 million reduction in compensation expense, primarily due to lower non-cash share-based compensation and a decrease in cash severance charges incurred with the departure of an executive officer during the fourth quarter of 2019. Additionally, the decrease in 2020 compared to 2019 was due in part to a reduction in professional fees of $1.0 million.
General and administrative expenses in 2019 as compared to 2018 were higher primarily due to a $5.7 million increase in compensation expense, $4.1 million of which was an increase in non-cash share-based compensation, due in part to additions to our executive team that occurred late in the second quarter of 2018 and the timing of our 2018 and 2019 performance-based equity awards. The increase in 2019 was also due to a $0.8 million cash severance charge incurred with the departure of an executive officer during the fourth quarter of 2019 and $1.8 million in legal and advisory fees incurred in 2019 in connection with the VEN Bakken Acquisition.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $162.1 million in 2020 compared to $210.2 million in 2019 and $119.8 million in 2018. Depletion expense, the largest component of DD&A, was $13.27 per Boe in 2020 compared to $14.84 per Boe in 2019 and $12.75 per Boe in 2018. The aggregate decrease in depletion expense for 2020 compared to 2019 was driven by a 14% decrease in production levels and a 11% decrease in the depletion rate per Boe. The 2020 depletion rate per Boe was lower due to the impact of impairments in 2020. The aggregate increase in depletion expense for 2019 compared to 2018 was driven by a 51% increase in production levels and a 16% increase in the depletion rate per Boe. The 2019 depletion rate per Boe was higher due to an increase in well costs and the impact of acquisitions in 2019. The following table summarizes DD&A expense per Boe for 2020, 2019 and 2018:
| ||Year Ended December 31,||Year Ended December 31,|
|Depletion||$||13.27 ||$||14.84 ||$||(1.57)||(11)||%||$||14.84 ||$||12.75 ||$||2.09 ||16 ||%|
|Depreciation, Amortization, and Accretion||0.12 ||0.08 ||0.04 ||50 ||%||0.08 ||0.12 ||(0.04)||(33)||%|
|Total DD&A expense||$||13.39 ||$||14.92 ||$||(1.53)||(10)||%||$||14.92 ||$||12.87 ||$||2.05 ||16 ||%|
Impairment of Oil and Natural Gas Properties
As a result of low commodity prices and their effect on the proved reserve values of our properties, we recorded a non-cash ceiling test impairment of $1,066.7 million in 2020. We did not record any impairment of our proved oil and gas properties in 2019 or 2018. The impairment charge affected our reported net income but did not reduce our cash flow.
Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods.
Interest expense, net of capitalized interest, was $58.5 million in 2020 compared to $79.2 million in 2019 and $86.0 million in 2018. The decrease in interest expense for 2020 as compared to 2019 was primarily due to a reduction in our outstanding debt balance during 2020 and lower interest rates on our Revolving Credit Facility. The decrease in interest expense for 2019 as compared to 2018 was primarily due to lower interest rates on our Revolving Credit Facility compared to our prior term loan facility, which was retired in October 2018.
Loss on the Extinguishment of Debt
As a result of a series of exchange transactions of our Second Lien Notes (see Note 4 to our financial statements), we recorded a loss on the extinguishment of debt of $3.7 million for the year ended December 31, 2020 based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof. During 2019, we recorded a loss on extinguishment of debt of $23.2 million as a result of early redemptions of our Second Lien Notes (see Note 4 to our financial statements), based on the differences between the reacquisition costs of retiring the applicable debt and the net carrying values thereof. During 2018, we recorded a loss on extinguishment of debt of $173.4 million as a result of early redemptions of our prior senior unsecured notes and our prior term loan facility.
Debt Exchange Derivative Gain (Loss)
We incurred debt exchange derivative liabilities during 2018 in connection with certain exchange transactions with respect to previously outstanding senior unsecured notes. During the years ended December 31, 2019 and 2018, we recorded a debt exchange derivative liability gain of $1.4 million and loss of $0.6 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2019, there were no remaining outstanding debt exchange derivative liabilities, and as a result there were no associated gains or losses during 2020.
Contingent Consideration Gain (Loss)
We incurred contingent consideration liabilities during 2018 in connection with certain acquisitions of oil and gas properties that closed in 2018. During the years ended December 31, 2019 and 2018, we recorded contingent consideration losses of $29.5 million and $29.0 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2019, there were no remaining outstanding contingent consideration liabilities, and as a result there were no associated gains or losses during 2020.
Income Tax Benefit
We recognized income tax benefit of $0.2 million, zero, and $0.1 million in 2020, 2019, and 2018, respectively. The effective tax rate was zero in each of 2020, 2019, and 2018, due to our full valuation allowance on our deferred tax assets. In 2020 and 2018, the tax benefits recognized related to the utilization of our alternative minimum tax credit as a result of favorable tax incentives. We have recorded a valuation allowance against effectively all of our net deferred tax assets due to uncertainty regarding their realization.
We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. Release of any portion of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change on the basis of the level of profitability that we are able to actually achieve. For further discussion of our valuation allowance, see Note 10 to our financial statements.
Non-GAAP Financial Measures
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. Net income (loss) is the most directly comparable GAAP measure for both Adjusted Net Income and Adjusted EBITDA, and tabular reconciliations for these measures are included below. We recorded a net loss of $906.0 million (representing $21.55 per diluted share) for 2020, compared to a net loss of $76.3 million (representing $2.00 per diluted share) for 2019 and net income of $143.7 million (representing $6.07 per diluted share) for 2018.
We define Adjusted Net Income (Loss) as net income (loss) excluding (i) unrealized (gain) loss on unsettled commodity derivatives, net of tax, (ii) financing expense, net of tax, (iii) impairment of other current assets, net of tax, (iv) write-off of debt issuance costs, net of tax, (v) loss on the extinguishment of debt, net of tax, (vi) debt exchange derivative (gain) loss, net of tax, (vii) contingent consideration loss, net of tax, (viii) acquisition transaction costs, net of tax, (ix) impairment expense, net of tax, and (x) loss on unsettled interest rate derivatives, net of tax. Our Adjusted Net Income for 2020 was $96.0 million (representing $1.82 per diluted share) as compared to Adjusted Net Income for 2019 of $120.9 million (representing $3.06 per diluted share) and Adjusted Net Income of $140.7 million (representing $5.94 per diluted share) for 2018. The decrease in Adjusted Net Income in 2020 compared to 2019 was primarily due to lower realized commodity prices (after the effect of settled derivatives), lower production volumes and increased per unit production expenses, which were partially offset by lower interest costs. The increase in Adjusted Net Income in 2019 compared to 2018 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth and lower interest costs, partially offset by increased per unit expenses and lower realized commodity prices (after the effect of settled derivatives).
We define Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) (gain) loss on unsettled commodity derivatives, (v) non-cash stock based compensation expense, (vi) write-off of debt issuance costs, (vii) loss on the extinguishment of debt, (viii) impairment of other current assets, (ix) debt exchange derivative (gain) loss, (x) contingent consideration loss, (xi) financing expense, (xii) impairment expense, (xiii) (gain) loss on unsettled interest rate derivatives, and (xiv) cash severance expense. Adjusted EBITDA for 2020 was $351.8 million, compared to Adjusted EBITDA of $454.2 million in 2019 and $349.3 million in 2018. The decrease in Adjusted EBITDA in 2020 as compared to 2019 was primarily due to lower production volumes, higher per unit production expenses, and lower realized commodity prices (after the effect of settled derivatives). The increase in Adjusted EBITDA in 2019 as compared to 2018 was primarily due to significantly higher production volumes as a result of our acquisitions and organic growth, partially offset by increased per unit expenses and lower realized commodity prices (after the effect of settled derivatives).
Management believes the use of these non-GAAP financial measures provide useful information to investors to gain an overall understanding of our current financial performance. Specifically, management believes the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain items that our management believes are not indicative of our core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring our performance, and we believe that we are providing investors with financial measures that most closely align to our internal measurement processes. We consider these non-GAAP measures to be useful in evaluating our core operating results as they provide useful information regarding our essential revenue generating activities and direct operating expenses (resulting in cash expenditures) needed to perform these revenue generating activities. Our management also believes, based on feedback provided by the investment community, that the non-GAAP financial measures are necessary to allow the investment community to construct its valuation models to better compare our results with our competitors and market sector.
These measures should be considered in addition to our results of operations prepared in accordance with GAAP. In addition, these non-GAAP financial measures are not based on any comprehensive set of accounting rules or principles. We believe that non-GAAP financial measures have limitations in that they do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures.
Reconciliation of Adjusted Net Income
| ||Years Ended December 31,|
|(In thousands, except share and per share data)||2020||2019||2018|
|Net Income (Loss)||$||(906,041)||$||(76,318)||$||143,689 |
|Add:|| || || |
|Impact of Selected Items:|| || || |
|(Gain) Loss on Unsettled Commodity Derivatives||(39,878)||173,214 ||(207,892)|
|Impairment Expense||1,066,668 ||— ||— |
|Financing Expense||— ||1,447 ||884 |
|Impairment of Other Current Assets||— ||6,398 ||— |
|Write-off of Debt Issuance Costs||1,543 ||— ||— |
|Loss on the Extinguishment of Debt||3,718 ||23,187 ||173,430 |
|Debt Exchange Derivative (Gain) Loss||— ||(1,390)||598 |
|(Gain) Loss on Unsettled Interest Rate Derivatives||1,019 ||— ||— |
|Contingent Consideration Loss||169 ||29,512 ||28,968 |
|Acquisition Transaction Costs||— ||1,763 ||— |
|Selected Items, Before Income Taxes||1,033,240 ||234,130 ||(4,012)|
Income Tax of Selected Items(1)
|Selected Items, Net of Income Taxes||1,002,076 ||197,232 ||(3,029)|
|Adjusted Net Income||$||96,035 ||$||120,914 ||$||140,660 |
|Weighted Average Shares Outstanding – Basic||42,744,639 ||38,708,460 ||23,620,646 |
|Weighted Average Shares Outstanding – Diluted||52,659,217 ||39,482,135 ||23,677,391 |
|Net Income (Loss) Per Common Share – Basic||$||(21.20)||$||(1.97)||$||6.08 |
|Add:|| || || |
|Impact of Selected Items, Net of Income Taxes||23.45 ||5.09 ||(0.12)|
|Adjusted Net Income Per Common Share – Basic||$||2.25 ||$||3.12 ||$||5.95 |
|Net Income (Loss) Per Common Share – Diluted||$||(17.21)||$||(1.93)||$||6.07 |
|Add:|| || || |
|Impact of Selected Items, Net of Income Taxes||19.03 ||4.99 ||(0.13)|
|Adjusted Net Income Per Common Share – Diluted||$||1.82 ||$||3.06 ||$||5.94 |
(1)The 2020 column represents a tax impact using an estimated tax rate of 24.5% and includes an adjustment of $222.0 million for changes in our valuation allowance. The 2019 column represents a tax impact using an estimated tax rate of 24.5% and includes an adjustment of $20.5 million for changes in our valuation allowance. The 2018 column represents a tax impact using an estimated tax rate of 24.5% and does not include any adjustments for changes in our valuation allowance.
Reconciliation of Adjusted EBITDA
| ||Year Ended December 31,|
|Net Income (Loss)||$||(906,041)||$||(76,318)||$||143,689 |
|Add:|| || || |
|Interest Expense||58,503 ||79,229 ||86,005 |
|Income Tax Provision (Benefit)||(166)||— ||(55)|
|Depreciation, Depletion, Amortization and Accretion||162,120 ||210,201 ||119,780 |
|Impairment of Other Current Assets||— ||6,398 ||— |
|Non-Cash Stock-Based Compensation||4,119 ||7,955 ||3,876 |
|Write-off of Debt Issuance Costs||1,543 ||— ||— |
|Loss on the Extinguishment of Debt||3,718 ||23,187 ||173,430 |
|Debt Exchange Derivative (Gain) Loss||— ||(1,390)||598 |
|Contingent Consideration Loss||169 ||29,512 ||28,968 |
|Financing Expense||— ||1,447 ||884 |
|Cash Severance Expense||— ||759 ||— |
|(Gain) Loss on Unsettled Interest Rate Derivatives||1,019 ||— ||— |
|(Gain) Loss on Unsettled Commodity Derivatives||(39,878)||173,214 ||(207,892)|
|Impairment Expense||1,066,668 ||— ||— |
|Adjusted EBITDA||351,774 ||454,193 ||349,283 |
Liquidity and Capital Resources
Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings, and cash settlements of commodity derivative instruments. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
As of December 31, 2020, we had outstanding debt consisting of $532.0 million of borrowings under our Revolving Credit Facility, $287.8 million aggregate principal amount of our 8.500% senior secured second lien notes due 2023 (the “Second Lien Notes”) and $130.0 million aggregate principal amount under our 6.0% Senior Unsecured Promissory Note due 2022 (the “Unsecured VEN Bakken Note”). We had $129.4 million in liquidity as of December 31, 2020, consisting of $128.0 million of borrowing availability under the Revolving Credit Facility and $1.4 million of cash on hand.
Subsequent to the end of 2020, in February 2021, we entered into an agreement to acquire producing natural gas properties in the Appalachian Basin from Reliance Marcellus, LLC (the “Reliance Acquisition”), which we anticipate will close in April 2021. In February 2021, we also completed a number of significant financing transactions, including:
•a common stock offering with estimated net proceeds of $132.4 million, which is primarily intended to finance a portion of the cash purchase price for the pending Reliance Acquisition;
•the issuance of $550.0 million in aggregate principal amount of new 8.125% senior unsecured notes due 2028 (the “2028 Notes”), with estimated net proceeds of $537.0 million that are primarily intended to refinance the Second Lien Notes, refinance the Unsecured VEN Bakken Note, fund any remaining cash purchase price for the pending Reliance Acquisition, and repay borrowings under the Revolving Credit Facility;
•fully repaid and retired the Unsecured VEN Bakken Note; and
•redeemed and retired $272.1 million in aggregate principal amount of our Second Lien Notes pursuant to a cash tender offer, leaving $15.7 million in aggregate principal amount of Second Lien Notes remaining outstanding immediately thereafter.
See Note 14 to our financial statements for further details regarding the pending Reliance Acquisition and the February 2021 financing transactions described above.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 77% and 80% of our total production volumes in 2020 and 2019, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain a robust hedging program to mitigate volatility in the price of crude oil with respect to a portion of our expected oil production. For the years ended 2020 and 2019, we hedged approximately 104% and 76% of our crude oil production, respectively. For a summary as of December 31, 2020, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.
Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.
Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments.
At December 31, 2020, we had a working capital deficit of $56.8 million, compared to a deficit of $70.4 million at December 31, 2019. Current assets decreased by $7.4 million and current liabilities decreased by $21.0 million at December 31, 2020, compared to December 31, 2019. The decrease in current assets in 2020 as compared to 2019 is primarily due to a decrease of $37.3 million in accounts receivable primarily due to our lower production levels and reduced commodity prices and a lower cash balance, which was partially offset by an increase of $45.7 million in our derivative instruments, due to the change in fair value as a result of oil price projections. The change in current liabilities in 2020 as compared to 2019 is primarily due to a decrease of $75.3 million in accounts payable and accrued expenses primarily as a result of reduced development activity and an $8.2 million decrease in derivative instruments as a result of forward oil price changes, which was partially offset by the current maturity of our first Unsecured VEN Bakken Note payment of $65.0 million that was paid on January 4, 2021. Additionally, our accrued interest was reduced by $3.3 million as a result of lower levels of debt outstanding in 2020 as compared to 2019.
Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. The Company typically enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months. As of December 31, 2020, we had entered into oil derivative swap contracts hedging 7.5 million barrels of oil in 2021 at an average price of $55.06 per barrel and 0.8 million barrels of oil in 2022 at an average price per barrel of $50.49. In addition, we had entered into natural gas derivative swap contracts hedging 13.0 million MMbtu in 2021 at an average price of $2.50 per MMbtu, and 3.7 million MMbtu in 2022 at an average price of $2.61 per MMbtu. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”
Our cash flows for the years ended December 31, 2020, 2019 and 2018 are presented below:
| ||Year Ended December 31,|
|Net Cash Provided by Operating Activities||$||331,685 ||$||339,750 ||$||244,262 |
|Net Cash Used for Investing Activities||(283,926)||(569,128)||(474,519)|
|Net Cash Provided by (Used for) Financing Activities||(62,399)||243,088 ||130,431 |