UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________
FORM 10-K
☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2022 |
or
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to |
Commission File Number: 001-32886
_______________________________
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
_______________________________
Oklahoma | 73-0767549 | ||||||
(State or other | (I.R.S. Employer | ||||||
20 N. Broadway, | Oklahoma City, | Oklahoma | 73102 | ||||
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (405) (405) 234-9000
Securities registered pursuant to Section 12(b) of the Act:
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
¨NoxIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
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
¨NoxIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 | ☐ | |||
Non-accelerated filer | x | 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. ¨
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 20172022 was approximately $2.8$4.1 billion, based upon the closing price of $32.33$65.35 per share as reported by the New York Stock Exchange on such date.
Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding at the time of our $0.01 par value common stock were outstanding on January 31, 2018.
DOCUMENTS INCORPORATED BY REFERENCE
Part III (Items 10, 11, 12, 13 and 14) of this Annual Report on Form 10-K is incorporated by reference from the definitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of Shareholdersregistrant’s amendment to this Form 10-K to be held in May 2018, which will be filed on Form 10-K/A with the Securities and Exchange Commission withinno later than 120 days after the end of the registrant’s fiscal year are incorporatedcovered by reference into Part III of this Form 10-K.report.
Table of Contents
PART I | ||
Item 1. | 1 | |
2 | ||
2 | ||
3 | ||
3 | ||
6 | ||
7 | ||
7 | ||
9 | ||
10 | ||
10 | ||
10 | ||
11 | ||
11 | ||
17 | ||
18 | ||
Item 1A. | 19 | |
Item 1B. | 29 | |
Item 2. | 29 | |
Item 3. | 29 | |
Item 4. | 30 | |
PART II | ||
Item 5. | 31 | |
Item 6. | 31 | |
Item 7. | 32 | |
Item 7A. | 46 | |
Item 8. | 48 | |
Item 9. | 86 | |
Item 9A. | 86 | |
Item 9B. | 88 | |
Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 88 |
PART III | ||
Item 10. | 89 | |
Item 11. | 89 | |
Item 12. | 89 | |
Item 13. | 89 | |
Item 14. | 89 | |
PART IV | ||
Item 15. | 90 |
Glossary of Crude Oil and Natural Gas Terms
The terms defined in this section may be used throughout this report:
“basin”
A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.“Bbl”
One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.“Bcf”
One billion cubic feet of natural gas.“Boe”
Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.“Btu”
British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.“completion”
The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.“conventional play”
An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.“DD&A”
Depreciation, depletion, amortization and accretion.“
de-risked” Refers to acreage and locations in which the Company believes the geological risks and uncertainties related to recovery of crude oil and natural gas have been reduced as a result of drilling operations to date. However, only a portion of such acreage and locations have been assigned proved undeveloped reserves and ultimate recovery of hydrocarbons from such acreage and locations remains subject to all risks of recovery applicable to other acreage.“developed acreage”
The number of acres allocated or assignable to productive wells or wells capable of production.“development well”
A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.“dry hole”
Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.“enhanced recovery”
The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.“exploratory well”
A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.“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.“fracture stimulation”
A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Also may be referred to as hydraulic fracturing.“gross acres”
or “gross wells” Refers to the total acres or wells in which a working interest is owned.“held by production”
or “HBP” Refers to an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.“horizontal drilling”
A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.“MBbl”
One thousand barrels of crude oil, condensate or natural gas liquids.i
“Mcf”
One thousand cubic feet of natural gas.“MMBo”
One million barrels of crude oil.“MMBoe”
One million Boe.“MMBtu”
One million British thermal units.“MMcf”
One million cubic feet of natural gas.“net acres”
or “net wells” Refers to the sum of the fractional working interests owned in gross acres or gross wells."Net crude oil and natural gas sales" Represents total crude oil, natural gas, and natural gas liquids sales less total transportation expenses. Net crude oil, natural gas, and natural gas liquids sales presented herein is a non-GAAP measure. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
"Net sales price" Represents the average net wellhead sales price received by the Company for sales after deducting transportation expenses. Net sales price is calculated by taking revenues less transportation expenses divided by sales volumes for a period. Net sales prices presented herein are non-GAAP measures. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
“NGL” or "NGLs" Refers to natural gas liquids, which are hydrocarbon products that are separated during natural gas processing and include ethane, propane, isobutane, normal butane, and natural gasoline.
“NYMEX”
The New York Mercantile Exchange.“pad drilling” or “pad development”
Describes a well site layout which allows for drilling multiple wells from a single pad resulting in less environmental impact and lower per-well drilling and completion costs.“play”
A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.“productive well”
A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.“prospect”
A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.“proved reserves”
The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.“proved developed reserves”
Reserves expected to be recovered through existing wells with existing equipment and operating methods.“proved undeveloped reserves”
or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.“PV-10”
When used with respect to crude oil and natural gas reserves, PV-10 represents the estimated future gross revenues to be generated from the production of proved reserves using a 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December, net of estimated production and future development and abandonment costs based on costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities and Exchange Commission (“SEC”). PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company’s crude oil and natural gas properties. The Company and others in the industry use PV-10 as aii
measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
“reservoir”
A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.“residue gas” Refers to gas that has been processed to remove natural gas liquids.
“resource play”
Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.“royalty interest”
Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.“SCOOP”
Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko basin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.“STACK”
Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations.“spacing”
The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.“Standardized Measure”
Discounted future net cash flows estimated by applying the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December 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 net cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis in the crude oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.“unconventional play”
An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.“undeveloped acreage”
Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.“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.“well bore”
The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called a well or borehole.“working interest”
The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.iii
Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “target,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include, but are not limited to, statements about:
Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and
iv
uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors and elsewhere in this report registration statements we file from time to time with the Securities and Exchange Commission, and other disclosures or announcements we make from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Additionally, new factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, the Company’sCompany's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.
Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
v
Part I
You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “Continental,” “we,” “us,” “our,” “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiaries.
Item 1. Business
Take-private transaction
On October 16, 2022, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Pursuant to the Merger Agreement, on November 22, 2022 Merger Sub completed a tender offer to purchase any and all of the outstanding shares of the Company’s common stock for $74.28 per share in cash, other than: (i) shares of common stock owned by Mr. Hamm, certain of his family members and their affiliated entities (collectively, the “Hamm Family”) and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans. Immediately prior to the consummation of the Offer, Mr. Hamm contributed 100% of the capital stock of Merger Sub to the Company, as a result of which Merger Sub became a wholly owned subsidiary of the Company. Following consummation of the Offer, Merger Sub merged with and into the Company, with the Company continuing as the surviving corporation wholly owned by the Hamm Family.
Following the completion of the transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (ii) our common stock was deregistered under Section 12(b) of the Securities Exchange Act of 1934 as amended (the “Exchange Act”), and (iii) we suspended our reporting obligations under Section 15(d) of the Exchange Act. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer apply to us. We will continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures.
See Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction for additional information.
Nature of business
We are an independent crude oil and natural gas company with properties in the North, South and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
We focus our exploration activities in large new or developing crude oil and natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations.and apply our geologic and operational expertise to drill and develop properties at attractive rates of return. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture stimulation), pad/row development, and enhanced recovery technologies allow us to develop and produce crude oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drill bit.
As of December 31, 2017,2022, our estimated proved reserves were 1,3311,864 MMBoe, with estimated proved developed reserves of 602representing 1,035 MMBoe, or 45%56%, of our total estimated proved reserves. Crude oil represents approximately 48% of our estimated proved reserves as of December 31, 2017. The standardized measure of our discounted future net cash flows totaled approximately $10.5$31.91 billionat December 31, 2017.
1
The table below summarizes our total estimated proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, 2017,2022 and our average daily production for the quarter ended December 31, 2017 and the reserve-to-production index in2022 for our principal operating areas. The PV-10 values shown below are not intended to represent the fair market value of our crude oil and natural gas properties. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. See
|
| December 31, 2022 |
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|
|
|
|
|
| |||||||||||||||
|
| Proved |
|
| Percent |
|
| PV-10 (1) |
|
| Net |
|
| 4Q 2022 Daily Production (Boe per day) |
|
| Percent |
| ||||||
Bakken |
|
| 733,875 |
|
|
| 39.4 | % |
| $ | 17,802 |
|
|
| 2,098 |
|
|
| 174,397 |
|
|
| 41.7 | % |
Anadarko Basin |
|
| 697,219 |
|
|
| 37.4 | % |
| $ | 12,060 |
|
|
| 845 |
|
|
| 165,225 |
|
|
| 39.5 | % |
Powder River Basin |
|
| 103,941 |
|
|
| 5.6 | % |
| $ | 2,106 |
|
|
| 433 |
|
|
| 28,057 |
|
|
| 6.7 | % |
Permian Basin |
|
| 303,799 |
|
|
| 16.3 | % |
| $ | 7,367 |
|
|
| 364 |
|
|
| 44,925 |
|
|
| 10.7 | % |
All other |
|
| 24,930 |
|
|
| 1.3 | % |
| $ | 626 |
|
|
| 257 |
|
|
| 5,552 |
|
|
| 1.4 | % |
Total |
|
| 1,863,764 |
|
|
| 100.0 | % |
| $ | 39,961 |
|
|
| 3,997 |
|
|
| 418,156 |
|
|
| 100.0 | % |
December 31, 2017 | Average daily production for fourth quarter 2017 (Boe per day) | Annualized reserve/production index (2) | ||||||||||||||||||||
Proved reserves (MBoe) | Percent of total | PV-10 (1) (In millions) | Net producing wells | Percent of total | ||||||||||||||||||
North Region: | ||||||||||||||||||||||
Bakken field | ||||||||||||||||||||||
North Dakota Bakken | 594,818 | 44.7 | % | $ | 6,488 | 1,313 | 158,640 | 55.3 | % | 10.3 | ||||||||||||
Montana Bakken | 40,703 | 3.1 | % | 412 | 263 | 6,958 | 2.4 | % | 16.0 | |||||||||||||
Red River units | ||||||||||||||||||||||
Cedar Hills | 28,998 | 2.2 | % | 340 | 130 | 7,022 | 2.4 | % | 11.3 | |||||||||||||
Other Red River units | 2,668 | 0.2 | % | 28 | 117 | 2,475 | 0.9 | % | 3.0 | |||||||||||||
Other | 1,356 | 0.1 | % | 9 | 8 | 468 | 0.2 | % | 7.9 | |||||||||||||
South Region: | ||||||||||||||||||||||
SCOOP | 491,776 | 36.9 | % | 3,597 | 260 | 62,242 | 21.7 | % | 21.6 | |||||||||||||
STACK | 167,390 | 12.6 | % | 936 | 160 | 47,914 | 16.7 | % | 9.6 | |||||||||||||
Other | 3,286 | 0.2 | % | 23 | 175 | 1,266 | 0.4 | % | 7.1 | |||||||||||||
Total | 1,330,995 | 100.0 | % | $ | 11,833 | 2,426 | 286,985 | 100.0 | % | 12.7 |
Our Our business strategies leadership team has significant experience with operating in challenging commodity price environments. With our portfolio of high quality assets, we are well-positioned to manage the ongoing challenges and price volatility facing our industry.For 2018, our primaryBusiness Strategieswill focus on:Balancing strong production growth with free cash flow generation;Enhancing cash flows and return on capital employed through improvements in operating efficiencies, technical innovations, and optimized completion methods;Continuing to exercise disciplined capital spending to maintain financial flexibility and ample liquidity; andImproving debt metrics by further reducing outstanding debt using available operating cash flows or proceeds from asset dispositions or joint development arrangements.Based on an expectation for higher operating cash flows in 2018 in response to improvement in crude oil prices in late 2017 and early 2018, we have increased our planned non-acquisition capital spending for 2018 to $2.3 billion compared to $2.0 billion spent in 2017, with approximately 78% of our 2018 drilling and completion budget focusing on oil-weighted areas inthe North Dakota Bakken and SCOOP Springer plays. We expect to fund our budgeted spending using cash flows from operations. We may adjust our pace of drilling and development as 2018 market conditions evolve.For 2018, we plan to operate an average of approximately 21drilling rigs and 10completion crews for the year. We expect to spend approximately 52%of our 2018 capital expenditures budget on drilling and completion activities in North Dakota Bakken, 20%in SCOOP, and 14% in STACK. The remaining 14%of our 2018 budget will target other capital expenditures such as leasing and renewals, work-overs, and facilities. See the section below titled Summary of Crude Oil and Natural Gas Properties and Projects for further discussion of our 2018 plans.Our Business StrategyDespite ongoing volatility and uncertainty in commodity prices, our business strategy continuescontinue to be focused on increasing shareholderenterprise value by finding and developing crude oil and natural gas reserves at low costs that provideand attractive rates of return. The principal elements of this strategyFor 2023, our primary business strategies will include:
Our Business Strengths
We holdhave a portfolionumber of leaseholdstrengths to allow us to successfully execute our business strategies, including the following:
Large acreage drilling opportunitiesinventory with access to both crude oil and uncompleted wellsnatural gas resources. We held 605,179 net undeveloped acres and 1.52 million net developed acres under lease as of December 31, 2022 concentrated in certaincore areas of premier U.S. resource plays with varyingthat provide optionality and access to crude oil, natural gas, and natural gas liquids. We pursue opportunities to develop our existing properties as well as explore for new resource plays where significant reserves may be economically developed. Our capital programs are designed to allocate investments to projects that provide opportunities to deliver strong production growth while generating cash flows in excess of operating
Expertise with pad and Control 2 allow for uninterrupted flow back and recycling capabilities, supports timely completion activities, and generates additional service revenues and cash flows. Experienced Management Team Financial Position and Liquidity Crude Oil and Natural Gas Operations Proved Reserves Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence The Our estimated proved reserves and related future net revenues, Standardized Measure and PV-10 at December 31, capital requirements, to work down our large inventory of uncompleted wells, to convert our undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries and rates of return on capital employed. While our operations have historically focused on the exploration androw development, of crude oil, we also allocate significant capital to natural gas areas that provide attractive rates of return.Enhance cash flows and return on capital employed through costs reductions, operating efficiencies, technical innovations,horizontal drilling, and optimized completions. We continue to manage through the current commodity price environment by focusing on improving operating efficiencies and reducing costs. Our key operating areas are characterized by large acreage positions in select unconventional resource plays with multiple stacked geologic formations that provide repeatable drilling opportunities and resource potential. We operate a significant portion of our wells and leasehold acreage and believe the concentration of our operated assets allows us to leverage our technical expertise and manage the development of our properties to achieve cost reductions through operating efficiencies and economies of scale.We continued to achieve efficiency gains in various aspects of our business in 2017, including additional reductions in spud-to-total depth drilling times and average days to drill horizontal laterals, which has led to reductions in drilling costs in our core areas. In addition to lowering our drilling costs, we also work to enhance cash flows through the use of optimized completion technologies that help improve recoveries and rates of return. These efforts have had a positive impact on the efficiency of our capital deployed in recent years, resulting in significant improvement in the quantity of reserves found and developed per dollar invested.Maintaining financial flexibility and a strong balance sheet. Maintaining a strong balance sheet, ample liquidity, and financial flexibility are key components of our business strategy. In 2017, we reduced our total debt by $226 million, or 3%, from $6.58 billion at year-end 2016 to $6.35 billion at year-end 2017. We are actively targeting further debt reduction using available cash flows from operations or proceeds from potential sales of non-strategic assets and joint development opportunities and will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.Focusing on organic growth through disciplined capital investments. Although we consider various growth opportunities, including property acquisitions, our primary focus is on organic growth through leasing and drilling in our core areas where we can exploit our extensive inventory of repeatable drilling opportunities to achieve attractive rates of return. From January 1, 2015 through December 31, 2017, our proved reserve additions through extensions and discoveries were 743 MMBoe compared with insignificant proved reserve acquisitions during that same period.Our Business StrengthsWe have a number of strengths we believe will help us successfully execute our business strategy, including the following:Large Acreage Inventory. We held approximately 598,400 net undeveloped acres and 1.19 million net developed acres under lease as of December 31, 2017 concentrated in certain premier U.S. resource plays. We are among the largest leaseholders in the Bakken, SCOOP and STACK plays. Being an early entrant in these plays has allowed us to capture significant acreage positions in core parts of the plays.Expertise with Horizontal Drilling and Optimized Completion Methodsmethods. We have substantial experience with horizontal drilling and optimized completion methods and continue to be among industry leaders in the use of new drilling and completion technologies. We continue to improve drilling and completion efficiencies through the use of multi-well pad drilling in our operating areas.and row development strategies. Further, we are among industry leaders in drilling long lateral lengths. We have also been among industry leaders in testing and utilizing optimized completion technologies involving various combinations of fluid types, proppant types and volumes, and stimulation stage spacing to determine optimal methods for improving recoveries and rates of return. We continually refine our drilling and completion techniques in an effort to deliver improved results across our properties.Operations Overoperations over a Substantial Portionsubstantial portion of Our Assetsour assets and Investments2017,2022, we operated properties comprising 89%88% of our total proved reserves. By controlling a significant portion of our operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and completion methods used.industry.industry and with operating in challenging commodity price environments. Our Chief Executive Officer,Chairman, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 9 senior7 executive officers have an average of 3840 years of oil and gas industry experience.Currently weWe have a revolving credit facility with lender commitments totaling $2.75$2.255 billion that matures in May 2019.October 2026. We had approximately $2.65$1.12 billion of available borrowing capacity underavailability on our credit facility at January 31, 2018February 1, 2023 after considering outstanding borrowings and letters of credit. Downgrades of our credit rating will, however, trigger increases in our credit facility’s interest rates and commitment fees paid on unused borrowing availability under certain circumstances.that the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott Company, L.P (“Ryder Scott”), our independent reserve engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole, production, seismic, and well test data.following table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2017.2022. Proved reserves attributable to noncontrolling interests are not material relative to our consolidated reserves and are not separately presented herein. The standardized measure of our discounted future net cash flows totaled approximately $10.5$31.91 billion at December 31, 2017.2022. Our reserve estimates as of December 31, 20172022 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 96%98% of our PV-10 and 96%98% of our total proved reserves as of December 31, 2017.2022. Our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K.20172022 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 20172022 through December 2017,2022, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $51.34$93.67 per Bbl for crude oil and $2.98$6.36 per MMBtu for natural gas ($47.0389.47 per Bbl for crude oil and $3.00$6.12 per Mcf for natural gas adjusted for location and quality differentials).
The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2022.
|
| Crude Oil |
|
| Natural Gas |
|
| Total |
|
| PV-10 (1) |
| ||||
Proved developed producing |
|
| 439,497 |
|
|
| 3,417,413 |
|
|
| 1,009,066 |
|
| $ | 23,468.8 |
|
Proved developed non-producing |
|
| 14,802 |
|
|
| 69,361 |
|
|
| 26,362 |
|
|
| 580.0 |
|
Proved undeveloped |
|
| 435,240 |
|
|
| 2,358,578 |
|
|
| 828,336 |
|
|
| 15,912.6 |
|
Total proved reserves |
|
| 889,539 |
|
|
| 5,845,352 |
|
|
| 1,863,764 |
|
| $ | 39,961.4 |
|
Standardized Measure (1) |
|
|
|
|
|
|
|
|
|
| $ | 31,907.6 |
|
Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | PV-10 (1) (in millions) | ||||||||||
Proved developed producing | 318,291 | 1,697,926 | 601,279 | $ | 7,474.9 | ||||||||
Proved developed non-producing | 416 | 1,235 | 622 | 6.4 | |||||||||
Proved undeveloped | 322,242 | 2,441,120 | 729,094 | 4,352.2 | |||||||||
Total proved reserves | 640,949 | 4,140,281 | 1,330,995 | $ | 11,833.5 | ||||||||
Standardized Measure (1) | $ | 10,470.2 |
3
The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2017.
Proved Developed | Proved Undeveloped | |||||||||||||||||
Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | |||||||||||||
North Region: | ||||||||||||||||||
Bakken field | ||||||||||||||||||
North Dakota Bakken | 217,776 | 472,057 | 296,452 | 212,107 | 517,562 | 298,366 | ||||||||||||
Montana Bakken | 21,503 | 38,480 | 27,916 | 10,385 | 14,412 | 12,787 | ||||||||||||
Red River units | ||||||||||||||||||
Cedar Hills | 28,321 | 4,058 | 28,998 | — | — | — | ||||||||||||
Other Red River units | 2,667 | 16 | 2,668 | — | — | — | ||||||||||||
Other | 110 | 7,469 | 1,356 | — | — | — | ||||||||||||
South Region: | ||||||||||||||||||
SCOOP | 35,333 | 754,820 | 161,136 | 84,828 | 1,474,871 | 330,640 | ||||||||||||
STACK | 12,181 | 407,448 | 80,089 | 14,922 | 434,275 | 87,301 | ||||||||||||
Other | 816 | 14,813 | 3,286 | — | — | — | ||||||||||||
Total | 318,707 | 1,699,161 | 601,901 | 322,242 | 2,441,120 | 729,094 |
|
| Proved Developed |
|
| Proved Undeveloped |
| ||||||||||||||||||
|
| Crude Oil |
|
| Natural Gas |
|
| Total |
|
| Crude Oil |
|
| Natural Gas |
|
| Total |
| ||||||
Bakken |
|
| 221,714 |
|
|
| 1,047,607 |
|
|
| 396,315 |
|
|
| 220,634 |
|
|
| 701,555 |
|
|
| 337,560 |
|
Anadarko Basin |
|
| 77,781 |
|
|
| 2,072,290 |
|
|
| 423,163 |
|
|
| 57,863 |
|
|
| 1,297,162 |
|
|
| 274,056 |
|
Powder River Basin |
|
| 34,382 |
|
|
| 154,902 |
|
|
| 60,199 |
|
|
| 27,782 |
|
|
| 95,760 |
|
|
| 43,742 |
|
Permian Basin |
|
| 95,707 |
|
|
| 210,681 |
|
|
| 130,821 |
|
|
| 128,961 |
|
|
| 264,101 |
|
|
| 172,978 |
|
All other |
|
| 24,715 |
|
|
| 1,294 |
|
|
| 24,930 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total |
|
| 454,299 |
|
|
| 3,486,774 |
|
|
| 1,035,428 |
|
|
| 435,240 |
|
|
| 2,358,578 |
|
|
| 828,336 |
|
The following table provides information regarding changes in total estimated proved reserves for the periods presented.
Year Ended December 31, | |||||||||
MBoe | 2017 | 2016 | 2015 | ||||||
Proved reserves at beginning of year | 1,274,864 | 1,225,811 | 1,351,091 | ||||||
Revisions of previous estimates | (82,012 | ) | (110,474 | ) | (297,198 | ) | |||
Extensions, discoveries and other additions | 240,206 | 249,430 | 253,173 | ||||||
Production | (88,562 | ) | (79,390 | ) | (80,926 | ) | |||
Sales of minerals in place | (15,197 | ) | (10,513 | ) | (329 | ) | |||
Purchases of minerals in place | 1,696 | — | — | ||||||
Proved reserves at end of year | 1,330,995 | 1,274,864 | 1,225,811 |
|
| Year Ended December 31, |
| |||||||||
MBoe |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Proved reserves at beginning of year |
|
| 1,645,310 |
|
|
| 1,103,762 |
|
|
| 1,619,265 |
|
Revisions of previous estimates |
|
| (133,061 | ) |
|
| 53,569 |
|
|
| (504,874 | ) |
Extensions, discoveries and other additions |
|
| 395,490 |
|
|
| 371,105 |
|
|
| 91,387 |
|
Production |
|
| (146,657 | ) |
|
| (120,321 | ) |
|
| (109,833 | ) |
Sales of minerals in place |
|
| (144 | ) |
|
| (148 | ) |
|
| — |
|
Purchases of minerals in place |
|
| 102,826 |
|
|
| 237,343 |
|
|
| 7,817 |
|
Proved reserves at end of year |
|
| 1,863,764 |
|
|
| 1,645,310 |
|
|
| 1,103,762 |
|
Revisions of previous estimates.
RevisionsExtensions, discoveries and other additions.
Sales of minerals in place.
Purchases of minerals in place. Purchases in 2022 and 2021 were primarily attributable to our acquisitions of properties during a period. See
4
Proved Undeveloped Reserves
All of our PUD reserves at December 31, 20172022 are located in the Bakken, SCOOP, and STACK plays, our most active development areas, with those plays comprising 43%, 45%, and 12%, respectively, of our total PUD reserves at year-end 2017.areas. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2017.2022. Our PUD reserves at December 31, 20172022 include 7084 MMBoe of reserves associated with wells where drilling has occurred but the wells have not been completed or are completed but not producing ("DUC wells"). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells.
Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | |||||||
Proved undeveloped reserves at December 31, 2016 | 353,018 | 2,419,198 | 756,218 | ||||||
Revisions of previous estimates | (73,684 | ) | (131,306 | ) | (95,569 | ) | |||
Extensions and discoveries | 100,874 | 492,468 | 182,952 | ||||||
Sales of minerals in place | (3,441 | ) | (24,870 | ) | (7,586 | ) | |||
Purchases of minerals in place | 149 | 3,009 | 650 | ||||||
Conversion to proved developed reserves | (54,674 | ) | (317,379 | ) | (107,571 | ) | |||
Proved undeveloped reserves at December 31, 2017 | 322,242 | 2,441,120 | 729,094 |
|
| Crude Oil |
|
| Natural Gas |
|
| Total |
| |||
Proved undeveloped reserves at December 31, 2021 |
|
| 369,377 |
|
|
| 2,209,532 |
|
|
| 737,632 |
|
Revisions of previous estimates |
|
| (95,108 | ) |
|
| (570,693 | ) |
|
| (190,223 | ) |
Extensions, discoveries and other additions |
|
| 173,738 |
|
|
| 1,033,726 |
|
|
| 346,025 |
|
Sales of minerals in place |
|
| — |
|
|
| — |
|
|
| — |
|
Purchases of minerals in place |
|
| 42,165 |
|
|
| 129,872 |
|
|
| 63,810 |
|
Conversion to proved developed reserves |
|
| (54,932 | ) |
|
| (443,859 | ) |
|
| (128,908 | ) |
Proved undeveloped reserves at December 31, 2022 |
|
| 435,240 |
|
|
| 2,358,578 |
|
|
| 828,336 |
|
Revisions of previous estimates.
Extensions, discoveries and discoveries.
Sales of Crude Oilminerals in place. We had no individually significant dispositions of PUD reserves in 2022.
Purchases of minerals in place. Purchases in 2022 were primarily attributable to our acquisitions of properties in the Permian Basin and Natural Gas Properties and Projects
Conversion to proved developed reserves.
InDUC Wells | |||||||||
Gross | Net | PUD Reserves (MBoe) | |||||||
DUC wells at December 31, 2016 | 279 | 145 | 95,272 | ||||||
Wells converted to proved developed reserves | (203 | ) | (110 | ) | (75,274 | ) | |||
Wells added | 209 | 72 | 51,306 | ||||||
Revisions | (7 | ) | (2 | ) | (1,707 | ) | |||
DUC wells at December 31, 2017 | 278 | 105 | 69,597 |
Development plans.
We have acquired substantial leasehold positions inEstimated future development costs relating to the development of PUD reserves at December 31, 2022 are projected to be approximately $1.0 billion in 2018 (44% of total capital budget), $1.5 billion in 2019,2023, $1.7 billion in 2020, $1.52024, $2.6 billion in 2021, and $0.72025, $2.1 billion in 2022.2026, and $1.7 billion in 2027. These capital expenditure projections are reflective of the current commodity price environment and have been established based on an expectation of drilling and completion costs, available cash flows, borrowing capacity, and borrowing capacity.the commodity price environment in effect at the time of preparing our reserve estimates and may be adjusted as market conditions evolve. Development of our existing PUD reserves at December 31, 2017, including those associated with DUC wells,2022 is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be developeddrilled within five years of initial booking because of changes in business strategy depressed commodity prices, or for other reasons have been removed from our reserves at December 31, 2017.2022. We had no PUD reserves at December 31, 20172022 that remain undevelopedundrilled beyond five years from the date of initial booking.
5
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Ryder Scott, our independent reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 96%98% of our PV-10 and 96%98% of our total proved reserves as of December 31, 20172022 included in this Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Form 10-K for further discussion of the qualifications of Ryder Scott personnel.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team is in contact regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. Proved reserves information is reviewed by our Audit Committee with representativescertain members of Ryder Scott and by our internal technical staffsenior management before the information is filed with the SEC on Form 10-K. Additionally, certain members of our senior management review and approve the Ryder Scott reserves report and on a semi-annual basis review any internal proved reserves estimates.
Our Vice President—Manager of Corporate Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, an MBA in Finance and 3338 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Vice President—Manager of Corporate Reserves reports directly to our Vice ChairmanPresident of Strategic Growth Initiatives.Resource and Business Development. The reserves estimates are reviewed and approved by certain members of the Company's President and certain other members of senior management.
Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2017:
Developed acres | Undeveloped acres | Total | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
North Region: | ||||||||||||||||||
Bakken field | ||||||||||||||||||
North Dakota Bakken | 951,645 | 556,044 | 147,513 | 90,288 | 1,099,158 | 646,332 | ||||||||||||
Montana Bakken | 170,899 | 137,594 | 30,059 | 17,601 | 200,958 | 155,195 | ||||||||||||
Red River units | 158,967 | 139,418 | 26,719 | 13,124 | 185,686 | 152,542 | ||||||||||||
Other | 102,542 | 66,399 | 94,454 | 68,597 | 196,996 | 134,996 | ||||||||||||
South Region: | ||||||||||||||||||
SCOOP | 230,799 | 133,756 | 260,257 | 143,116 | 491,056 | 276,872 | ||||||||||||
STACK | 211,836 | 118,563 | 177,563 | 93,846 | 389,399 | 212,409 | ||||||||||||
Other | 67,734 | 32,928 | 71,250 | 33,067 | 138,984 | 65,995 | ||||||||||||
East Region | 449 | 404 | 161,935 | 138,799 | 162,384 | 139,203 | ||||||||||||
Total | 1,894,871 | 1,185,106 | 969,750 | 598,438 | 2,864,621 | 1,783,544 |
|
| Developed acres |
|
| Undeveloped acres |
|
| Total |
| |||||||||||||||
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
Bakken |
|
| 1,127,004 |
|
|
| 703,277 |
|
|
| 78,098 |
|
|
| 43,582 |
|
|
| 1,205,102 |
|
|
| 746,859 |
|
Anadarko Basin |
|
| 604,876 |
|
|
| 350,084 |
|
|
| 236,552 |
|
|
| 123,201 |
|
|
| 841,428 |
|
|
| 473,285 |
|
Powder River Basin |
|
| 242,000 |
|
|
| 179,069 |
|
|
| 288,525 |
|
|
| 198,747 |
|
|
| 530,525 |
|
|
| 377,816 |
|
Permian Basin |
|
| 111,880 |
|
|
| 102,366 |
|
|
| 127,710 |
|
|
| 85,382 |
|
|
| 239,590 |
|
|
| 187,748 |
|
All other |
|
| 243,269 |
|
|
| 189,259 |
|
|
| 216,135 |
|
|
| 154,267 |
|
|
| 459,404 |
|
|
| 343,526 |
|
Total |
|
| 2,329,029 |
|
|
| 1,524,055 |
|
|
| 947,020 |
|
|
| 605,179 |
|
|
| 3,276,049 |
|
|
| 2,129,234 |
|
The following table sets forth the number of gross and net undeveloped acres as of December 31, 20172022 scheduled to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates or the leases are renewed.
2018 | 2019 | 2020 | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
North Region: | ||||||||||||||||||
Bakken field | ||||||||||||||||||
North Dakota Bakken | 20,557 | 12,742 | 2,890 | 1,544 | 29,318 | 20,170 | ||||||||||||
Montana Bakken | 14,713 | 9,489 | 400 | 400 | — | — | ||||||||||||
Red River units | 5,617 | 3,318 | 2,879 | 1,365 | — | — | ||||||||||||
Other | 9,264 | 5,849 | 20,097 | 13,877 | 4,520 | 1,795 | ||||||||||||
South Region: | ||||||||||||||||||
SCOOP | 75,650 | 41,718 | 68,307 | 37,774 | 51,635 | 31,767 | ||||||||||||
STACK | 40,196 | 22,346 | 72,528 | 38,450 | 31,777 | 17,782 | ||||||||||||
Other | 1,840 | 504 | 28,258 | 12,251 | 23,513 | 11,986 | ||||||||||||
East Region | 6,947 | 6,292 | 55,347 | 40,336 | 11,728 | 10,164 | ||||||||||||
Total | 174,784 | 102,258 | 250,706 | 145,997 | 152,491 | 93,664 |
|
| 2023 |
|
| 2024 |
|
| 2025 |
| |||||||||||||||
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
Bakken |
|
| 11,207 |
|
|
| 7,639 |
|
|
| 14,290 |
|
|
| 9,363 |
|
|
| 2,760 |
|
|
| 1,498 |
|
Anadarko Basin |
|
| 39,321 |
|
|
| 15,348 |
|
|
| 33,771 |
|
|
| 16,314 |
|
|
| 66,712 |
|
|
| 45,523 |
|
Powder River Basin |
|
| 3,938 |
|
|
| 1,712 |
|
|
| 7,593 |
|
|
| 3,021 |
|
|
| 2,701 |
|
|
| 2,504 |
|
Permian Basin |
|
| 845 |
|
|
| 639 |
|
|
| 56,798 |
|
|
| 47,839 |
|
|
| 41,781 |
|
|
| 12,523 |
|
All other |
|
| 57,243 |
|
|
| 55,212 |
|
|
| 32,989 |
|
|
| 15,545 |
|
|
| 13,489 |
|
|
| 10,466 |
|
Total |
|
| 112,554 |
|
|
| 80,550 |
|
|
| 145,441 |
|
|
| 92,082 |
|
|
| 127,443 |
|
|
| 72,514 |
|
6
Drilling Activity
During the three years ended December 31, 2017,2022, we drilledparticipated in the drilling and completedcompletion of exploratory and development wells as set forth in the table below:
2017 | 2016 | 2015 | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
Exploratory wells: | ||||||||||||||||||
Crude oil | 34 | 9.0 | 39 | 11.4 | 28 | 19.8 | ||||||||||||
Natural gas | 9 | 3.1 | 15 | 4.2 | 19 | 1.4 | ||||||||||||
Dry holes | — | — | — | — | 1 | 1.0 | ||||||||||||
Total exploratory wells | 43 | 12.1 | 54 | 15.6 | 48 | 22.2 | ||||||||||||
Development wells: | ||||||||||||||||||
Crude oil | 474 | 175.4 | 245 | 54.7 | 707 | 215.5 | ||||||||||||
Natural gas | 91 | 26.8 | 66 | 21.6 | 142 | 32.8 | ||||||||||||
Dry holes | — | — | — | — | — | — | ||||||||||||
Total development wells | 565 | 202.2 | 311 | 76.3 | 849 | 248.3 | ||||||||||||
Total wells | 608 | 214.3 | 365 | 91.9 | 897 | 270.5 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||||||||||||||
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
Exploratory wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Crude oil |
|
| 17 |
|
|
| 12.1 |
|
|
| 11 |
|
|
| 8.0 |
|
|
| 1 |
|
|
| — |
|
Natural gas |
|
| 2 |
|
|
| — |
|
|
| 2 |
|
|
| 1.9 |
|
|
| 1 |
|
|
| — |
|
Dry holes |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| 0.9 |
|
Total exploratory wells |
|
| 20 |
|
|
| 13.1 |
|
|
| 13 |
|
|
| 9.9 |
|
|
| 3 |
|
|
| 0.9 |
|
Development wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Crude oil |
|
| 407 |
|
|
| 153.6 |
|
|
| 376 |
|
|
| 144.6 |
|
|
| 300 |
|
|
| 115.5 |
|
Natural gas |
|
| 65 |
|
|
| 28.8 |
|
|
| 38 |
|
|
| 20.3 |
|
|
| 31 |
|
|
| 15.9 |
|
Dry holes |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total development wells |
|
| 472 |
|
|
| 182.4 |
|
|
| 414 |
|
|
| 164.9 |
|
|
| 331 |
|
|
| 131.4 |
|
Total wells |
|
| 492 |
|
|
| 195.5 |
|
|
| 427 |
|
|
| 174.8 |
|
|
| 334 |
|
|
| 132.3 |
|
As of December 31, 2017,2022, there were 475427 gross (179(178 net)
Summary of Crude Oil and Natural Gas Properties and Projects
Following is a discussion we review our budgeted number of wells and capital expenditures for 20182022 activities in our key operating areas. Our 2018 capital budget has been set based on an expectation of available cash flows in order to minimize the incurrence of new debt. If cash flows are materially impacted by a decline in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our revolving credit facility if needed to fund our operations. Conversely, higher cash flows resulting from an increase in commodity prices could result in increased capital expenditures.
2018 Plan | ||||||||||
Gross wells (1) | Net wells (1) | Capital expenditures (in millions) (2) | ||||||||
North Region: | ||||||||||
Bakken | 415 | 143 | $ | 1,193 | ||||||
South Region: | ||||||||||
SCOOP | 160 | 44 | 465 | |||||||
STACK and Other | 181 | 38 | 330 | |||||||
Total exploration and development drilling | 756 | 225 | $ | 1,988 | ||||||
Land | 132 | |||||||||
Capital facilities, workovers and other corporate assets | 168 | |||||||||
Seismic | 12 | |||||||||
Total 2018 capital budget, excluding acquisitions | $ | 2,300 |
Bakken Field
The Bakken field of North Dakota and Montana is one of the premierlargest crude oil resource plays in the United States. We are a leadingthe largest producer and leasehold owner and operator in the Bakken. As of December 31, 2017,2022, we controlled one of the largest leasehold positionsheld approximately 1.2 million gross (746,900 net) acres under lease in the Bakken with approximately 1.3 million gross (801,500 net) acres under lease.
Our total Bakken production averaged 165,598174,397 Boe per day for the fourth quarter of 2017, up 58%2022, down 1% from the 20162021 fourth quarter. For the year ended December 31, 2017,2022, our average daily Bakken production increased 12% over 2016. We increased our drilling and well completion activities in the Bakken in 2017, particularly in the second half of the year, in response1% compared to stabilization and improvement in crude oil prices.2021. In 2017,2022, we participated in the drilling and completion of 370266 gross (145(93 net) wells in the Bakken compared to 192252 gross (38(102 net) wells completed in 2016. Our 2017 activities in the Bakken focused on development of de-risked, higher rate-of-return areas in core parts of North Dakota and the testing of various optimized completion methods aimed at improving crude oil recoveries and rates of return.
Our Bakken properties represented 48%39% of our total proved reserves at December 31, 20172022 and 58%42% of our average daily Boe production for the 20172022 fourth quarter. Our total proved Bakken field reserves as of December 31, 20172022 were 636734 MMBoe, an increase of 7%4% compared to December 31, 2016 due to reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017.2021. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,2521,173 gross (656(596 net) wells as of December 31, 2017.
Anadarko Basin
We are a leading producer, leasehold owner and improvement in crude oil prices in late 2017 and early 2018 we plan to increase our activities in North Dakota Bakken in 2018 relative to 2017. In 2018, we plan to invest approximately $1.19 billionoperator in the play,Anadarko Basin of Oklahoma, which includes $413 million for the completionSCOOP and initiationSTACK areas of production on operated Bakken wells that were drilled but not completed as of year-end 2017. We plan to operate, on average, six rigs in North Dakota Bakken throughout 2018, an increase from four rigs asthe play. As of December 31, 2017. Additionally,2022, we plan to use, on average, six to seven well completion crewscontrolled one of the largest leasehold positions in North Dakota Bakken throughout 2018, consistentthe Anadarko Basin with our current activity levels. Our 2018 drilling and completion activities will focus on core parts of North Dakota Bakken that provide opportunities to improve capital efficiency, reduce finding and development costs, and improve recoveries and rates of return.
Our properties in the South regionAnadarko Basin represented 50%37% of our total proved reserves as of December 31, 20172022 and 39%40% of our average daily Boe production for the fourth quarter of 2017.2022. Production in the Anadarko Basin averaged 165,225 Boe per day during the fourth quarter of 2022, up 13% compared to the 2021 fourth quarter. For the 2017 fourth quarter, ouryear ended December 31, 2022, average daily production from such properties was 111,422 Boe per day,in the Anadarko Basin increased 7% compared to 2021. We participated in the drilling and completion of 155 gross (44 net) wells in the Anadarko Basin during 2022 compared to 161 gross (63 net) wells in 2021.
Our proved reserves in the Anadarko Basin as of December 31, 2022 totaled 697 MMBoe, an increase of 22% from the comparable period in 2016.3% compared to December 31, 2021. Our principal producing propertiesinventory of proved undeveloped drilling locations in the South region are locatedAnadarko Basin totaled 312 gross (159 net) wells as of December 31, 2022.
Powder River Basin
In 2021, we executed strategic acquisitions to expand our operations into the Powder River Basin of Wyoming and subsequently completed additional acquisitions in the SCOOP and STACK areas of Oklahoma.
7
Our 2017 activities in SCOOP focused on continued vertical and horizontal expansion of the productive extent and hydrocarbon content of the play and working to determine optimum well spacing, well patterns, and completion methods for future development.
Our proved reserves in SCOOPthe Powder River Basin totaled 492104 MMBoe as of December 31, 2017, an increase of 4%2022 compared to 32 MMBoe at December 31, 2016 due to reserves added from2021, and our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017. Our inventory of proved undeveloped drilling locations in SCOOPthe play totaled 33696 gross (230(57 net) wells as ofat year-end 2022.
Permian Basin
On December 31, 2017.
Our 2017 activities focused on pilot density drilling to expand our understanding of the productive extent and hydrocarbon content of the play and to help determine optimum well spacing, well patterns, and completion methods for future development.
Our proved reserves in 2016. Proved reserves increased 4% year-over-year to 167the Permian Basin totaled 304 MMBoe as of December 31, 2017 due2022 compared to reserves added from203 MMBoe at December 31, 2021, and our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017. Our inventory of proved undeveloped drilling locations in STACKthe play totaled 195261 gross (90(237 net) wells asat year-end 2022.
8
Production and Price History
The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2017, 20162022, 2021 and 20152020 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2017 (North Dakota Bakken2022.
|
| Year ended December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Net production volumes: |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbls) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
|
| 39,917 |
|
|
| 40,121 |
|
|
| 40,052 |
|
SCOOP |
|
| 10,051 |
|
|
| 11,318 |
|
|
| 12,585 |
|
Permian Basin |
|
| 11,832 |
|
|
| — |
|
|
| — |
|
Total Company |
|
| 72,827 |
|
|
| 58,636 |
|
|
| 58,745 |
|
Natural gas (MMcf) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
|
| 124,411 |
|
|
| 120,517 |
|
|
| 97,532 |
|
SCOOP |
|
| 185,755 |
|
|
| 179,553 |
|
|
| 136,410 |
|
Permian Basin |
|
| 20,804 |
|
|
| — |
|
|
| — |
|
Total Company |
|
| 442,980 |
|
|
| 370,110 |
|
|
| 306,528 |
|
Crude oil equivalents (MBoe) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
|
| 60,652 |
|
|
| 60,207 |
|
|
| 56,308 |
|
SCOOP |
|
| 41,010 |
|
|
| 41,244 |
|
|
| 35,320 |
|
Permian Basin |
|
| 15,300 |
|
|
| — |
|
|
| — |
|
Total Company |
|
| 146,657 |
|
|
| 120,321 |
|
|
| 109,833 |
|
Average net sales prices (1): |
|
|
|
|
|
|
|
|
| |||
Crude oil ($/Bbl) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
| $ | 89.91 |
|
| $ | 63.24 |
|
| $ | 33.53 |
|
SCOOP |
|
| 94.28 |
|
|
| 66.46 |
|
|
| 37.88 |
|
Permian Basin |
|
| 92.73 |
|
|
| — |
|
|
| — |
|
Total Company |
|
| 91.46 |
|
|
| 64.06 |
|
|
| 34.71 |
|
Natural gas ($/Mcf) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
| $ | 8.18 |
|
| $ | 4.52 |
|
| $ | 0.23 |
|
SCOOP |
|
| 6.87 |
|
|
| 5.33 |
|
|
| 1.64 |
|
Permian Basin |
|
| 6.95 |
|
|
| — |
|
|
| — |
|
Total Company |
|
| 7.01 |
|
|
| 4.88 |
|
|
| 1.04 |
|
Crude oil equivalents ($/Boe) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
| $ | 75.94 |
|
| $ | 51.21 |
|
| $ | 24.24 |
|
SCOOP |
|
| 54.25 |
|
|
| 41.44 |
|
|
| 19.90 |
|
Permian Basin |
|
| 81.13 |
|
|
| — |
|
|
| — |
|
Total Company |
|
| 66.58 |
|
|
| 46.24 |
|
|
| 21.47 |
|
Average costs per Boe: |
|
|
|
|
|
|
|
|
| |||
Production expenses ($/Boe) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
| $ | 5.05 |
|
| $ | 4.27 |
|
| $ | 4.35 |
|
SCOOP |
|
| 1.44 |
|
|
| 1.24 |
|
|
| 1.06 |
|
Permian Basin |
|
| 7.27 |
|
|
| — |
|
|
| — |
|
Total Company |
|
| 4.24 |
|
|
| 3.38 |
|
|
| 3.27 |
|
Production taxes ($/Boe) |
| $ | 4.98 |
|
| $ | 3.36 |
|
| $ | 1.75 |
|
General and administrative expenses ($/Boe) |
| $ | 2.74 |
|
| $ | 1.94 |
|
| $ | 1.79 |
|
DD&A expense ($/Boe) |
| $ | 12.86 |
|
| $ | 15.76 |
|
| $ | 17.12 |
|
Year ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
Net production volumes: | ||||||||||||
Crude oil (MBbls) | ||||||||||||
North Dakota Bakken | 35,964 | 31,723 | 37,539 | |||||||||
SCOOP | 5,726 | 6,807 | 7,198 | |||||||||
STACK | 3,166 | 1,552 | 245 | |||||||||
Total Company | 50,536 | 46,850 | 53,517 | |||||||||
Natural gas (MMcf) | ||||||||||||
North Dakota Bakken | 59,232 | 50,532 | 47,425 | |||||||||
SCOOP | 98,563 | 102,032 | 91,687 | |||||||||
STACK | 60,325 | 27,983 | 10,704 | |||||||||
Total Company | 228,159 | 195,240 | 164,454 | |||||||||
Crude oil equivalents (MBoe) | ||||||||||||
North Dakota Bakken | 45,836 | 40,145 | 45,444 | |||||||||
SCOOP | 22,153 | 23,813 | 22,479 | |||||||||
STACK | 13,220 | 6,216 | 2,029 | |||||||||
Total Company | 88,562 | 79,390 | 80,926 | |||||||||
Average sales prices: | ||||||||||||
Crude oil ($/Bbl) | ||||||||||||
North Dakota Bakken | $ | 45.21 | $ | 34.33 | $ | 39.76 | ||||||
SCOOP | 47.96 | 38.87 | 43.98 | |||||||||
STACK | 49.68 | 41.95 | 41.23 | |||||||||
Total Company | 45.70 | 35.51 | 40.50 | |||||||||
Natural gas ($/Mcf) | ||||||||||||
North Dakota Bakken | $ | 2.97 | $ | 1.05 | $ | 2.34 | ||||||
SCOOP | 3.26 | 2.24 | 2.39 | |||||||||
STACK | 2.43 | 1.87 | 2.06 | |||||||||
Total Company | 2.93 | 1.87 | 2.31 | |||||||||
Crude oil equivalents ($/Boe) | ||||||||||||
North Dakota Bakken | $ | 39.32 | $ | 28.45 | $ | 35.29 | ||||||
SCOOP | 26.93 | 20.71 | 23.81 | |||||||||
STACK | 22.89 | 18.88 | 15.87 | |||||||||
Total Company | 33.65 | 25.55 | 31.48 | |||||||||
Average costs per Boe: | ||||||||||||
Production expenses ($/Boe) | ||||||||||||
North Dakota Bakken | $ | 4.40 | $ | 4.59 | $ | 4.79 | ||||||
SCOOP | 1.01 | 1.13 | 1.10 | |||||||||
STACK | 1.22 | 1.00 | 3.52 | |||||||||
Total Company | 3.66 | 3.65 | 4.30 | |||||||||
Production taxes ($/Boe) | $ | 2.35 | $ | 1.79 | $ | 2.47 | ||||||
General and administrative expenses ($/Boe) | $ | 2.16 | $ | 2.14 | $ | 2.34 | ||||||
DD&A expense ($/Boe) | $ | 18.89 | $ | 21.54 | $ | 21.57 |
9
The following table sets forth information regarding our average daily production by region for the fourth quarter of 2017:
Fourth Quarter 2017 Daily Production | |||||||||
Crude Oil (Bbls per day) | Natural Gas (Mcf per day) | Total (Boe per day) | |||||||
North Region: | |||||||||
Bakken field | |||||||||
North Dakota Bakken | 124,811 | 202,975 | 158,640 | ||||||
Montana Bakken | 5,497 | 8,761 | 6,958 | ||||||
Red River units | |||||||||
Cedar Hills | 6,830 | 1,154 | 7,022 | ||||||
Other Red River units | 2,073 | 2,410 | 2,475 | ||||||
Other | 82 | 2,318 | 468 | ||||||
South Region: | |||||||||
SCOOP | 14,551 | 286,148 | 62,242 | ||||||
STACK | 13,788 | 204,754 | 47,914 | ||||||
Other | 434 | 4,998 | 1,266 | ||||||
Total | 168,066 | 713,518 | 286,985 |
|
| Fourth Quarter 2022 Daily Production |
| |||||||||
|
| Crude Oil |
|
| Natural Gas |
|
| Total |
| |||
Bakken |
|
| 114,594 |
|
|
| 358,820 |
|
|
| 174,397 |
|
Anadarko Basin |
|
| 31,403 |
|
|
| 802,930 |
|
|
| 165,225 |
|
Powder River Basin |
|
| 17,740 |
|
|
| 61,898 |
|
|
| 28,057 |
|
Permian Basin |
|
| 35,194 |
|
|
| 58,387 |
|
|
| 44,925 |
|
All other |
|
| 5,513 |
|
|
| 234 |
|
|
| 5,552 |
|
Total |
|
| 204,444 |
|
|
| 1,282,269 |
|
|
| 418,156 |
|
Productive Wells
Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interests owned in gross wells. The following table presents the total gross and net productive wells by region and by crude oil or natural gas completion as of December 31, 2017.
Crude Oil Wells | Natural Gas Wells | Total Wells | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
North Region: | ||||||||||||||||||
Bakken field | ||||||||||||||||||
North Dakota Bakken | 4,083 | 1,313 | — | — | 4,083 | 1,313 | ||||||||||||
Montana Bakken | 401 | 263 | — | — | 401 | 263 | ||||||||||||
Red River units | ||||||||||||||||||
Cedar Hills | 135 | 130 | — | — | 135 | 130 | ||||||||||||
Other Red River units | 131 | 117 | — | — | 131 | 117 | ||||||||||||
Other | 8 | 4 | 18 | 4 | 26 | 8 | ||||||||||||
South Region: | ||||||||||||||||||
SCOOP | 248 | 145 | 372 | 115 | 620 | 260 | ||||||||||||
STACK | 172 | 62 | 282 | 98 | 454 | 160 | ||||||||||||
Other | 139 | 110 | 167 | 65 | 306 | 175 | ||||||||||||
Total | 5,317 | 2,144 | 839 | 282 | 6,156 | 2,426 |
|
| Crude Oil Wells |
|
| Natural Gas Wells |
|
| Total Wells |
| |||||||||||||||
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
Bakken |
|
| 5,925 |
|
|
| 2,098 |
|
|
| — |
|
|
| — |
|
|
| 5,925 |
|
|
| 2,098 |
|
Anadarko Basin |
|
| 1,287 |
|
|
| 517 |
|
|
| 1,003 |
|
|
| 328 |
|
|
| 2,290 |
|
|
| 845 |
|
Powder River Basin |
|
| 553 |
|
|
| 424 |
|
|
| 12 |
|
|
| 9 |
|
|
| 565 |
|
|
| 433 |
|
Permian Basin |
|
| 395 |
|
|
| 356 |
|
|
| 9 |
|
|
| 8 |
|
|
| 404 |
|
|
| 364 |
|
All other |
|
| 270 |
|
|
| 252 |
|
|
| 29 |
|
|
| 5 |
|
|
| 299 |
|
|
| 257 |
|
Total |
|
| 8,430 |
|
|
| 3,647 |
|
|
| 1,053 |
|
|
| 350 |
|
|
| 9,483 |
|
|
| 3,997 |
|
Title to Properties
As is customary in the crude oil and natural gas industry, upon initiation of acquiring oil and gas leases covering fee mineral interests on undeveloped lands which do not have associated proved reserves, contract landmen conduct a title examination of courthouse records and production databases to determine fee mineral ownership and availability. Title, lease forms and final terms are reviewed and approved by Company landmen prior to consummation.
For acquisitions from third parties, whether lands are producing crude oil and natural gas or non-producing, Company and contract landmen perform title examinations at applicable courthouses, obtain physical well site inspections, and examine the seller’s internal records (land, legal, operational, production, environmental, well, marketing and accounting) upon execution of a mutually acceptable purchase and sale agreement. WeCompany landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.
Prior to the commencement of drilling operations, weCompany landmen procure an original title opinion, or supplement an existing title opinion, from outside legal counsel and perform curative work to satisfy requirements pertaining to material title defects,issues, if any. WeCompany landmen will not approve commencement of drilling operations until we have cured material title defects pertaining to the Company’s interest.
The Company has cured material defectstitle opinion issues as to Company interests on substantially all of ourits producing properties and believe we havebelieves it holds at least defensible title to ourits producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. OurThe Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the use ofCompany’s interest in the properties or affect ourthe Company’s carrying value of such properties.
Marketing and Major Customers
We sell most of our operated crude oil production is sold to either crude oil refining companies or midstream marketing companies at major market centers. Other operated production not sold at major market centers is sold at the lease. In the Bakken, Powder River, Permian, SCOOP, and STACK areas we have significant volumes of production directly connected to pipeline gathering systems, with the remaining balance of production being primarily transported by truck. Additionally in the Bakken, a portion of our production is sold to counterparties that are connected to rail delivery systems. Where directly marketed crude oil is transported by truck it is delivered to a point on a pipeline system for further delivery. We do not transport any of our oil production prior to sale by rail, but several purchasers of our Bakken production are connected to rail delivery or is delivered directlysystems and may choose those methods to a refinery. Wheretransport the oil they have purchased from us. We sell some operated crude oil is soldproduction at the lease the sale is complete at that point.lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.
10
We sell most of our operated natural gas and natural gas liquids production is soldto midstream customers at our lease locations to midstream purchasers under term contracts.based on market prices in the field where the sales occur, with the remaining production sold at centrally gathered locations or natural gas processing plants. These contracts include multi-year term agreements, many with acreage dedication. Some of our contracts allow usdedications. Under certain arrangements, we have the flexibilityright to accept, as partial payment for our sale of gas in the field, an “in-kind”take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream purchaser’scustomer's processing plant.plant in lieu of a monetary settlement for the sale of our operated natural gas production. When we electdo take volumes in kind, we pay third parties to do so,transport the volumes taken in kind to downstream delivery points, where we transport this processed gasthen sell to acustomers at prices applicable to those downstream market where it is sold.markets. Sales at thesethe downstream markets are mostly under daily and monthly interruptible packaged volumevolumes deals, shortshorter term seasonal packages, and long term multi-year contracts. We continue to develop relationships and have the potential to enter into additional contracts with end-use customers, including utilities, industrial users, and liquefied natural gas exporters, for sale of gasproducts we elect to take in-kind in lieu of cashmonetary settlement for our leasehold sales. Our share of natural gas and NGL production from non-operated properties is generally marketed at the discretion of the operators.
Competition
We operate in a highly competitive environment for acquiring properties, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources greater than ours, which can be particularly important in the areas in which we operate.ours. Those companies may be able to pay more for productive crude oil and natural gas properties, minerals, and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions economically in a highly competitive environment. In addition, as a result of the significant decrease in commodity pricessupply chain disruptions in recent years the numberhave led to shortages of providers ofcertain materials and services has decreased in the regions where we operate.equipment and increased costs. As a result, the likelihood of experiencing competition and shortages of materials and services may be further increasedincreased. Finally, the emerging impact of climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing demand for alternative forms of energy, and technological advances in connection with any period of commodity price recovery.
Regulation of the Crude Oil and Natural Gas Industry
All of our operations are conducted onshore almost entirely in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and interpretations affecting our industry have been and are pervasive with the frequent imposition of new or increased requirements on us and other industry participants.requirements. These laws, regulations and other requirements often carry substantial penalties for failure to comply and may have a significant effect on the exploration, development, production or sale of crude oilour operations and natural gas andmay increase the cost of doing business and affectreduce our profitability. In addition, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations. We do not expect any future legislative or regulatory initiatives will affect us in a manner materially different than they wouldwill affect our similarly situated competitors.
The following is a discussion of certain significant laws, rules and regulations, as amended from time to time, that may affect us in the areas in which we operate.
Regulation of sales and transportation of crude oil and natural gas liquids
Our physical sales of crude oil and any derivative instruments relating to crude oil we are requiredsubject to comply with anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”). SeeThese laws, among other things, prohibit fraudulent or deceptive conduct in connection with wholesale purchases or sales of crude oil and price manipulation in the discussion below of “Other Federal Lawscommodity and Regulations Affecting Our Industry—FTC and CFTC Market Manipulation Rules.”futures markets. If we violate the anti-market manipulation laws and regulations, we couldcan be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
We transport most of our operated crude oil production to market centers using a combination of trucks and pipeline transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration establishes safety regulations relating to transportation of crude oil by pipeline. Further, our sales of crude oil are affected by the availability, terms and costs of transportation. The transportation of crude oil and NGLs, as well as other liquid products,natural gas liquids (“NGLs”) is subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate crude oil and NGL pipeline transportation rates under the Interstate Commerce Act and the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. In general, pipeline rates must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. Oil and other liquid pipeline rates are often cost-based, although some pipeline charges today are based on historical rates adjusted for inflation and other factors, and other charges may result from settlement rates agreed to by all shippers or market-based rates, which are permitted in certain circumstances. FERC or interested persons may challenge existing or changed rates or services. Intrastateintrastate crude oil and NGL pipeline transportation rates may be subject to regulation by state regulatory commissions. The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. As the interstate and intrastate transportation rates we pay are generally applicable to all comparable shippers, the regulation of intrastatesuch transportation rates will not affect us in a way that materially differs from the effect on our similarly situated competitors.
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Further, interstate pipelines and intrastate common carrier pipelines must provide service on an equitable basis and offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When such pipelines operate at full capacity we are subject to proration provisions, which are described in the pipelines’ published tariffs. We generally will have access to crude oil pipeline transportation services to the same extent as our similarly situated competitors.
From time to time we may sell our operated crude oil production from our North region toat market centers using primarilyin the United States to third parties who then subsequently export and sell the crude oil in international markets. The International Maritime Organization (“IMO”), an agency of the United Nations, has issued regulations requiring the maritime shipping industry to gradually reduce its carbon emissions over time by mandating a combination1% improvement in the efficiency of pipelinefleets each year between 2015 and rail transportation facilities owned2025. In conjunction with this initiative, the IMO issued regulations requiring ship owners to lower the concentration of the sulfur content used in their fuels from 3.5% to 0.5% beginning on January 1, 2020. To achieve and operated by third parties. Approximately 6% of such production was shipped by rail in December 2017,maintain compliance with the remainder being shipped primarily by pipeline. The U.S. Department of Transportation’s (“U.S. DOT”) Pipelinenew regulations, it is expected ship owners will either have to switch to more expensive higher quality marine fuel, install and Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relatingutilize emissions-cleaning systems, or switch to transportation of crude oil by rail and pipeline. Third party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the U.S. DOT, the Federal Railroad Administration (“FRA”), the U.S. Occupational Safety and Health Administration ("OSHA"), and other federal regulatory agencies. Additionally, various state and local agencies have jurisdiction over disposal of hazardous waste and regulate movement of hazardous materials if not preempted by federal law.
We do not own or operate pipeline or rail transportation facilities, rail cars, or rail cars; however,infrastructure used to facilitate the exportation of crude oil. However, regulations that impact the testing or raildomestic transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at market centers throughout the United States, which could have a material adverse effect on our financial condition, results of operations and cash flows.States. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.
Regulation of Pipelinessales and Enhancing Safety Act (“PIPES Act”) was signed into law. The PIPES Act extends PHMSA’s safety authority through 2019 and includes provisions on advancing the safe transportation of energy commoditiesnatural gas
We are also required to observe the aforementioned anti-market manipulation laws and other hazardous materials. The PIPES Act includes provisions aimed at increasing inspection requirements for certain underwater crude oil pipelines; improving protectionrelated regulations enforced by the FERC and CFTC in connection with physical sales of coastal areas by designating them as environmentally sensitive to pipeline failures; setting minimum safety standards for underground natural gas storage facilities, and promoting better useany derivative instruments relating to natural gas. Additionally, the FERC regulates interstate natural gas transportation rates and service conditions under the Natural Gas Act and the Natural Gas Policy Act of data1978, which affects the marketing of natural gas we produce, as well as revenues we receive for sales of our natural gas. The FERC has endeavored to increase competition and technologymake natural gas transportation more accessible to prevent damagenatural gas buyers and improve safetysellers on an open and non-discriminatory basis and has issued a series of pipelineorders to implement its open access policies. We cannot provide any assurance the pro-competitive regulatory approach established by the FERC will continue. However, we do not believe any action taken by the FERC will affect us in a materially different way than similarly situated natural gas producers.
The gathering of natural gas, which occurs upstream of jurisdictional transmission services, is generally regulated by the states. Although its policies on gathering systems among other things. PHMSA published a final rule in January 2017 expanding integrity management and reporting requirements for certain hazardous liquid pipelines and gathering lines; however, implementation of the final rule was stayed following the change in U.S. Presidential Administrations. The final rule is expected to be publishedhave varied in the federal register duringpast, the first quarterFERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the potential to increase costs for our purchasers and reduce the revenues we receive for our natural gas stream. State regulation of 2018.natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, equitable take requirements. We do not expectbelieve such regulations will affect us in a materially different way than our similarly situated competitors.
Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas. 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 levelto state. Insofar as well. In December 2014such regulation within a particular state will generally affect all intrastate natural gas shippers on a comparable basis, the North Dakota Industrial Commission (“NDIC”) introduced rules designed to reduce the potential flammabilityregulation of crude oil produced from the Bakken petroleum system (the Bakken, Three Forks, and Sanish Pool formations) before it is loaded and transported on railcars. The rules became effectiveintrastate natural gas transportation in April 2015 and outline a series of standards for pressure and temperature for production facilities to followstates in order to separate certain liquids and gases from the crude oil prior to transport. These rules dowhich we operate will not affect us in a way that materially differs from our similarly situated competitors.
The U.S. Department of Energy (“U.S. DOE”) regulates the terms and conditions for the exportation and importation of natural gas (including liquefied natural gas or “LNG”). U.S. law provides for very limited regulation of exports to and imports from any country that has entered into a Free Trade Agreement (“FTA”) with the United States providing for national treatment of trade in natural gas; however, the U.S. DOE’s regulation of imports and exports from and to countries without an FTA is more comprehensive. The FERC also regulates the construction and operation of import and export facilities, including LNG terminals. Regulation of imports and exports and related facilities may materially affect natural gas markets and sales prices.
Regulation of production
The production of crude oil and natural gas is regulated by a wide range of federal, state, and local statutes,laws, rules, orders and regulations, which require, among other matters, permits for drilling operations, drilling bonds, and reports concerning operations. Each of the states
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where we own and operate properties have laws and regulations governing conservation, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, the plugging and abandonment of wells, the regulation of greenhouse gas emissions, and limitations or prohibitions on the venting or flaring of natural gas. These laws and regulations directly and indirectly limit the amount of crude oil and natural gas we can produce from our wells and the number of wells and locations we can drill, although we can and do apply for exceptions to such laws and regulations or to have reductions in well spacing. Moreover, each state generally imposes a production, severance or excise tax on the production and sale of crude oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with thesethe above laws, rules, and regulations can result in substantial penalties. Our similarly situated competitors are generally subject to the same statutes, regulatory requirements and restrictions.
Environmental regulation
General
. We are subject to stringent, complex, andThese laws, rules and regulations may restrict the level of substances generated by our operations that may be emitted into the air, discharged to surface water, and disposed or otherwise released to surface and below-ground soils and groundwater, and may also restrict the rate of crude oil and natural gas production belowto a rate otherwise possible.that is economically infeasible for continued production. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business and affects profitability. Additionally, in the U.S. Congressname of combatting climate change, President Biden has issued, and federal and state agencies frequently revise environmental laws, rules and regulations, and any changesmay continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry, or which restrict, delay or ban oil and gas permitting or leasing on federal lands. Any regulatory or executive changes that impose further requirements on domestic producers for emissions control, waste handling, disposal, cleanup and remediation requirements for the crude oil and natural gas industry could have a significant impact on our operating costs.
Air emissions and climate change
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Regulation of greenhouse gas emissions. The EPA has also adopted regulations underthreat of climate change continues to attract considerable attention in the United States and in foreign countries and, as a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit existing provisionsemissions of greenhouse gases as well as to reduce, restrict, or eliminate such future emissions. As a result, our operations as well as the operations of the federal Clean Air Actoil and gas industry in general are subject to a series of regulatory, political, litigation and financial risks associated with the production of fossil fuels and emission of greenhouse gases.
Federal regulatory initiatives have focused on establishing among other things, Prevention of Significant Deterioration (“PSD”) pre-constructionconstruction and Title V operating permit reviews for greenhouse gas emissions from certain large stationary sources. Moreover, the EPA’s source determination rule specifies that oil and gas production facilities are considered to be “adjacent” (and therefore aggregated for air permitting purposes) if they are on the same site or on sites that share equipment and are within ¼ mile of each other. This rule increases the potential for individual well facilities to be viewed collectively by the EPA as a single, large stationary source and, therefore, subject to PSD and/or Title V. Regulations related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
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 among participating nations to limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020. As part of the U.S.’s obligations under the Paris Agreement, the Biden Administration has announced a goal of reducing economy-wide net GHG emissions 50%-52% by 2030. Moreover, in November 2021 at the 26th Conference of the Parties (“COP26”), multiple announcements (not having the effect of law) were made, including a call for parties to eliminate certain measures perceived to subsidize fossil fuel production and consumption, and to pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative which over 100 counties joined, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States' commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.
Governmental, scientific and public concern over the threat of climate changes having significant physicalchange arising from greenhouse gas emissions has given rise to increasing federal political risk for the domestic crude oil and natural gas industry. In the United States, President Biden has issued several executive orders calling for more expansive action to address climate change and suspend new oil and gas operations on federal lands and waters. The suspension of the federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide permanent injunction by a federal district judge in Louisiana in August 2022, effectively halting implementation of the leasing suspension. Litigation risks are also increasing, as a number of states, municipalities and other parties have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as increased frequencyrising sea levels, and severitytherefore are responsible for roadway and infrastructure damages, or that the companies have been aware of storms, droughts, floodsthe adverse effects of climate change for some time but failed to adequately disclose those impacts.
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Moreover, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in energy companies but concerned about the potential effects of climate change may elect to shift some or all of their investments into non-energy related sectors. Institutional investors who provide financing to energy companies have also focused on sustainability lending practices that favor alternative power sources perceived to be more clean (despite their negative impacts on the environment), such as wind and solar. Some of these investors may elect not to provide traditional funding for energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. These and other climatic events. If any such effectsdevelopments in the financial sector could lead to some lenders restricting or eliminating access to capital for or divesting from such causes werecertain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to occur, they could have an adverse effectreduce their GHG emissions. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding to the fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on our explorationaddressing climate-related risks in the financial sector. In November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and production operations.
Environmental protection and natural gas flaring
.In addition, NDIC rules for new drilling permit applications also require the submission of gas capture plans addressing measuressetting forth plans taken by operators to capture and not flare produced gas, regardless of whether it has been or will be connected within the first year of production. Thus far, theThe NDIC has generally accepted our gas capture plans submitted with applications for drilling permits. The deadline to comply with the requirementcurrently requires us to capture 85%91% of the natural gas produced from a field was November 1, 2016, andfield. We capture in excess of the targetNDIC requirement. If an operator is unable to attain the applicable gas capture percentage increasesgoal at maximum efficient rate, wells will be restricted in production to 88% beginning November 1, 2018200 barrels of crude oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or otherwise crude oil production from such wells is not permitted to exceed 100 barrels of crude oil per day. However, the NDIC will consider temporary exemptions from the foregoing restrictions or for other types of extenuating circumstances after notice and 91% beginning November 1, 2020.hearing if the effect is a significant net increase in gas capture within one year of the date such relief is granted. Monetary penalty provisions also apply under this regulation if an operator fails to timely file for a hearing with the NDIC upon being unable to meet such percentage goals or if the operator fails to timely implement production restrictions once below the applicable percentage goals. Ongoing compliance with the NDIC’s flaring requirements or the imposition of any additional limitations on flaring could result in increased costs and have an adverse effect on our operations.
We seek to market, flaring approximately 10% compared to 9% in 2016 and 13% in 2015. According to data published by the NDIC, our industry as a whole flared approximately 12% of produced natural gas volumes in the North Dakota Bakken field during 2017. We are a participant in the NDIC’s Flaring Reduction Task Force and are engaged in working with other task force members and the NDIC to develop action plans for mitigatingreduce or eliminate natural gas flaring, in the state. Flared natural gas volumes frombut our operated SCOOP and STACK properties in Oklahoma are negligible given the existence of established natural gas transportation infrastructure.
Hydraulic fracturing
. Hydraulic fracturing involves the injection of water, sand or other proppant and additives under pressure into rock formations to stimulate crude oil and natural gas production. In recent years there has beenAt the federal level, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 related to such activities. In May 2014,Also, the EPA has issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. In June 2016, the EPA finalized a final regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities. It hasWe do not been our practice to discharge wastewater to publicly owned treatment works, so the impact of this new regulation on us is not currently, and is not expected to be, material.
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In Decemberlate 2016 the EPA published a final study of the potential impacts of hydraulic fracturing activities on water resources. In its report,resources in which the EPA indicated it found evidence hydraulic fracturingthat such activities can impact drinking water resources under some circumstances. The report identified certain conditions where impacts from hydraulic fracturing activities can potentially be more frequent or severe. These include water withdrawals for hydraulic fracturing in times or areas of low water availability; spills during the handling of hydraulic fracturing fluids, chemicals or produced water resulting in large volumes or high concentrations of chemicals reaching groundwater resources; injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity thereby allowing gases or liquids to move to groundwater resources; injection of hydraulic fracturing fluids directly into groundwater resources; discharge of inadequately treated hydraulic fracturing wastewater to surface water; and disposal or storage of hydraulic fracturing wastewater in unlined pits thereby resulting in contamination of groundwater resources. In its final report, the EPA indicated it was not able to calculate or estimate the national frequency of impacts on drinking water resources from hydraulic fracturing activities or fully characterize the severity of impacts. Nonetheless, the results of the EPA’s study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.
In March 2015,2016, the BLM issuedunder the Obama Administration published final rules related to the regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity, and handling of flowback water. Several parties challenged the regulations and the U.S. District Court of Wyoming temporarily stayed implementation of the regulations. In June 2016, the U.S. District Court of Wyoming ruledHowever, the BLM lackedunder the statutory authorityTrump Administration published a final rule rescinding the 2016 final rule in November 2018. Litigation challenging the BLM’s 2016 final rule as well as its 2018 final rule rescinding the 2016 rule has been pursued by various states and industry and environmental groups. While a California federal court vacated the 2018 final rule in July 2020, a Wyoming federal court subsequently vacated the 2016 final rule in October 2020 and, accordingly, the 2016 final rule is no longer in effect. However, appeals to promulgate the regulations.
In addition, regulators in states in which we operate have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating or prohibiting the time, place and manner of drilling activities or hydraulic fracturing activities. In certain areas of the United States, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards.
Waste water disposal.
The introduction of new environmental initiativeslaws and regulations related to the disposal of wastes associated with the exploration, development or production of hydrocarbons could limit or prohibit our ability to utilize underground injection wells. A lack of waste water disposal sites could cause us to delay, curtail or discontinue our exploration and development plans. Additionally, increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. These costs are commonly incurred by all oil and gas producers and we do not believeexpect the costs associated with the disposal of produced water will have a material adverse effect on our operations to any greater degree than other similarly situated competitors. In recent years, we have increased our operation and use of water recycling and distribution facilities in Oklahoma that economically reuse stimulation water for both operational efficiencies and environmental benefits.
We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Historically, our environmental compliance costs have not had a material adverse impact on our financial condition and results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material impact on our business, financial condition, results of operations or cash flows.
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Employee Health and Safety
. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable stateHuman Capital
Employees
As of December 31, 2017,2022, we employed 1,127 people. Our future success will depend partially on1,404 people, all of which were employed in the United States, with 790 employees being located at our abilitycorporate headquarters in Oklahoma City, Oklahoma and 614 employees located in our field offices located in Oklahoma, North Dakota, South Dakota, Montana, Wyoming, and Texas. None of our employees are subject to collective bargaining agreements. We believe our overall relations with our workforce are good.
Compensation
Because we operate in a highly competitive environment, we have designed our compensation program to attract, retain and motivate qualified personnel.experienced, talented individuals. Our program is also designed to align employee’s interests with those of our owners and to reward them for achieving the business and strategic objectives determined to be important to help the Company create and maintain advantage in a competitive environment. We are notalign our employee’s interests with those of our owners by making annual long-term incentive awards to virtually all of our salaried employees. We reward our employees for their performance in helping the Company achieve its annual business and strategic objectives through our bonus program, which is also available to virtually all of our employees. In order to ensure our compensation package remains competitive and fulfills our goal of recruiting and retaining talented employees, we consider competitive market compensation paid by other companies comparable to the Company in size, geographic location, and operations.
Safety
Safety is our highest priority and one of our core values. We promote safety with a party to any collective bargaining agreementsrobust health and have not experienced any strikes or work stoppages. We considersafety program that includes employee orientation and training, contractor management, risk assessments, hazard identification and mitigation, audits, incident reporting and investigation, and corrective/preventative action development.
Through our relations with“Brother’s Keeper” program, we encourage each of our employees to be satisfactory.a proactive participant in ensuring the safety of all of the Company’s personnel. We utilizedeveloped this program to leverage and continuously improve our ability to identify and prevent reoccurrence of unsafe behaviors and conditions. This program recognizes and rewards Company employees and contractors who observe and report outstanding safety and environmental behavior such as utilizing stop work authority, looking out for a co-worker, reporting incidents and near misses, or following proper safety procedures. This program positively impacts safety culture and performance and has contributed to a substantial increase in our reporting rates and to decreases in recordable incident and lost time incident rates.
Training and Development
We are committed to the servicestraining and development of independent contractorsour employees. We believe that supporting our employees in achieving their career and development goals is a key element of our approach to performattracting and retaining top talent. We have invested in a variety of resources to support employees in achieving their career and development goals, including developing learning paths for individual contributors and leaders, operating the Continental Leadership Learning Center which offers numerous instructor-led programs designed to foster employee development and maintaining a learning management system which provides access to numerous technical and soft skills online courses. We also invest time and resources in supporting the creation of individual development plans for our employees.
Health and Wellness
We offer various fieldbenefit programs designed to promote the health and well-being of our employees and their families. These benefits include medical, dental, and vision insurance plans; disability and life insurance plans; paid time off for holidays, vacation, sick leave, and other services.
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Diversity and Inclusion
We are committed to providing a diverse and inclusive workplace and career development opportunities to attract and retain talented employees. We prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, sexual orientation, gender identity, national origin, political affiliation, age, disability, genetic information, veteran status, or any other basis protected by local, state, or federal law. We also maintain a robust compliance program rooted in our Code of Business Conduct, which provides policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities.
We believe embracing diversity and inclusion is more than a matter of compliance. We recognize and appreciate the importance of creating an environment in which all employees feel valued, included, and empowered to do their best work and bring great ideas to the table. We believe a diverse and inclusive workforce provides the best opportunity to obtain unique perspectives, experiences, ideas, and solutions to help sustain our business success; a diverse and inclusive culture is the high-performance fuel that enhances our ability to innovate, execute and grow. To that end, we have implemented a long-term initiative for enhancing awareness of, and continuously improving our approach to, building and sustaining a diverse and inclusive culture. We have chartered a Diversity and Inclusion Committee comprised of employees across all company functions. We have engaged external training resources for our entire workforce, including interview training for hiring managers focused on ensuring a fair and systematic approach for recruiting and selecting individuals from diverse backgrounds for competitive job openings. We are intentional about proactively conducting outreach and recruitment at job fairs and other events hosted by diverse organizations. Through our Diversity and Inclusion Committee we provide new opportunities for our leadership and all employees to hold targeted discussions on issues related to diversity and inclusion, such as unconscious bias, disability inclusion, and equality through inclusive interaction. We are committed to continuous improvement in this critical area, evaluating more ways to sustain and strengthen our diverse and inclusive workforce.
Company Contact Information
Our corporate internet website is
www.clr.com. Through theWe intend to use our website as a means of disclosing material information and for complying with our disclosure obligations under SEC Regulation FD. Such disclosures will be included on our website in the “For Investors” section. Accordingly,
Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.
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Item 1A. Risk Factors
You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our debt securities. If any of the following risks develop into actual events, our business, financial condition, or results of operations, or cash flows could be materially adversely affected, the trading price of our securities could declineaffected.
Business and you may lose all or part of your investment.
Substantial declines in commodity prices or extended periods of low commodity prices adversely affect our business, financial condition, results of operations and cash flows and our ability to meet our capital expenditure needs and financial commitments.
The prices we receive for sales of our crude oil and natural gas production impact our revenue, profitability, cash flows, access to capital, capital budget, and rate of growth.growth, and carrying value of our properties. Crude oil and natural gas are commodities and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile and unpredictable. For example, during 2017 the NYMEX West Texas Intermediate (“WTI”) crude oilunpredictable and Henry Hub natural gas spotcommodity prices ranged from approximately $42 to $60 per barrel and $2.45 to $3.70 per MMBtu, respectively. Commodity prices maywill likely remain volatile and unpredictable in 2018 and beyond.
The prices we receive for sales of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
Sustained material declines in commodity prices reduce our cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; may limit our ability to borrow money or raise additional capital; and may reduce our proved reserves and the amount of crude oil and natural gas we can economically produce.
In addition to reducing our revenue, cash flows and earnings, depressed prices for crude oil and/or natural gas may adversely affect us in a variety of other ways. If commodity prices decrease substantially, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our
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estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to write down the carrying value of our crude oil and/or natural gas properties.
Lower commodity prices may also lead to reductions in our drilling and completion programs, which may result in insufficient production to satisfy our transportation and processing commitments. If production is not sufficient to meet our commitments we would incur deficiency fees that would need to be paid absent any cash inflows generated from the sale of production.
Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating
The ability or willingness of our producing properties is located in limited geographic areas, making us vulnerableSaudi Arabia and other members of OPEC, and other oil exporting nations, including Russia, to risks associated with having geographically concentrated operations.
OPEC is an intergovernmental organization that seeks to manage the price and natural gas production and approximately 64% of our crude oil and natural gas revenues for the year ended December 31, 2017. Approximately 48%
Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Our future financial condition and results of operations depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.
In this report, we describe our current prospects and key operating areas. Our management has specifically identified prospects and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of risks and uncertainties as described herein. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail our drilling and completion activities. Prospects we decide to drill that do not produce crude oil or natural gas in expected quantities may adversely affect our results of operations, financial condition, and rates of return on capital employed. The use of seismic data and other technologies and the study of producing fields in the financialsame area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present in expected or economically producible quantities. We cannot assure you the wells we drill will be as productive as anticipated or whether the analogies we draw from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects. Because of these uncertainties, we do not know if our potential drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations in sufficient quantities to achieve an economic return.
Risks we face while drilling include, but are not limited to, failing to place our well bore in the desired target producing zone; not staying in the desired drilling zone while drilling horizontally through the formation; failing to run our casing the entire length of the well bore; and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages; failing to run tools the entire length of the well bore during completion operations; not successfully cleaning out the well bore after completion of the final fracture stimulation stage; increased seismicity in areas near our completion activities; unintended interference of completion activities performed by us or by third parties with nearby operated or non-operated wells being drilled, completed, or producing; and failure of our optimized completion techniques to yield expected levels of production.
Further, many factors may occur that cause us to curtail, delay or cancel scheduled drilling and completion projects, including but not limited to:
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Any of the above risks could adversely impactaffect our accessability to conduct operations or result in substantial losses to us as a result of:
We are not insured against all risks associated with our business. We may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, pollution and environmental risks are generally not fully insurable.
Losses and liabilities arising from any of the above events could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations and cash flows.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company's current estimates of reserves could change, potentially in material amounts, in the future due to changes in commodity prices, business strategies, and other factors. Additionally, unless we replace our crude oil and natural gas reserves, our total reserves and production will decline, which could adversely affect our cash flows and results of operations.
The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could
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materially affect our estimated quantities and present value of our reserves. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves for information about our estimated crude oil and natural gas reserves, standardized measure of discounted future net cash flows, and PV-10 as of December 31, 2022.
In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data in preparing reserve estimates. The extent, quality and reliability of this data can vary which in turn can affect our ability to model the porosity, permeability and pressure relationships in unconventional resources. The process also requires economic assumptions, based on historical data projected into the future, about crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.
Actual future production, crude oil and natural gas sales prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves will vary and could vary significantly from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves, which in turn could have an adverse effect on the value of our assets. In addition, we may remove or adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development activities, changes in business strategies, prevailing crude oil and financial condition.
You should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. We base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may experience periodsbe materially higher or lower than the average prices used in the calculations. In addition, the use of turmoil and volatilitya 10% discount factor, which is required by the SEC to be used to calculate discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time resulting in diminished liquidity and credit availability,risks associated with our reserves or the crude oil and natural gas industry.
In addition, the development of our proved undeveloped reserves may take longer than anticipated and may not be ultimately developed or produced. At December 31, 2022, approximately 44% of our total estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2022 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $9.6 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to accessfund necessary capital markets, high unemployment, unstable consumer confidence,expenditures or otherwise, we may be required to remove the associated volumes from our reported proved reserves. Proved undeveloped reserves generally must be drilled within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and diminished consumer demandmay in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period. In 2022, 72MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with locations no longer scheduled to be drilled within five years from the date of initial booking due to the continual refinement of our drilling and spending. In recentdevelopment programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return.
Additionally, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. If we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years certain global economies have experienced periodsrepresents 41% of political uncertainty, slowing economic growth, rising interestour total net undeveloped acreage at December 31, 2022. At that date, we had leases representing 80,550 net acres expiring in 2023, 92,082 net acres expiring in 2024, and 72,514 net acres expiring in 2025.
Furthermore, unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates changing economic sanctions,that vary depending upon reservoir characteristics and currency volatility. These global macroeconomic conditions may put downward pressure on commodity pricesother factors. Our future crude oil and have a negative impactnatural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our revenues, profitability, operating cash flows, liquiditysuccess in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition.
Our business depends on crude oil and natural gas transportation, processing, refining, and export facilities, most of which are owned by third parties.
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The value we receive for our crude oil and natural gas production depends in part on the availability, proximity and capacity of gathering, pipeline and rail systems and processing, refining, and export facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. Although we have used cash flowssome contractual control over the transportation of our products, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our production becomes shut-in for any of these or other reasons, we will be unable to realize revenue from operations, borrowings underthose wells until other arrangements are made for the sale or delivery of our revolving credit facilityproducts and proceeds from capital market transactionsacreage lease terminations could result if production is shut-in for a prolonged period.
The disruption of transportation, processing, refining, or export facilities due to contractual disputes or litigation, labor disputes, maintenance, civil disturbances, international trade disputes, public protests, terrorist attacks, cyber attacks, adverse climatic events, natural disasters, seismic events, health epidemics and asset dispositions to fund capital expenditures. Volatilityconcerns, changes in U.S.tax and global financialenergy policies, federal, state and equity markets,international regulatory developments, changes in supply and demand, equipment failures or accidents, including market disruptions, limited liquidity,pipeline and interest rate volatility, maygathering system ruptures or train derailments, and general economic conditions could negatively impact our ability to obtain needed capitalachieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such facilities would be restored or the impact on acceptable termsprices in the areas we operate. A significant shut-in of production in connection with any of the aforementioned items could materially affect our cash flows, and if a substantial portion of the impacted production fulfills transportation or processing commitments or is hedged at alllower than market prices, those commitments or financial hedges would have to be paid from borrowings in the absence of sufficient operating cash flows.
Our operated crude oil and natural gas production is ultimately transported to downstream market centers in the United States primarily using transportation facilities and equipment owned and operated by third parties. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of regulations impacting the transportation of crude oil and natural gas. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. We do not currently own or operate infrastructure used to facilitate the transportation and exportation of crude oil; however, third party compliance with regulations that impact the transportation or exportation of our production may increase our costcosts of financing.
In response to a July 2020 U.S. District Court decision vacating the U.S. Army Corps of Engineers (“Corps”) grant of an easement to the Dakota Access Pipeline (“DAPL”) and issuance of an order requiring the Corps to conduct an Environmental Impact Statement (“EIS”) for the pipeline, the Corps is currently conducting the court-ordered environmental review to determine whether DAPL poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. DAPL currently remains in operation and, while the owners of DAPL appealed the District Court decision to the U.S. Supreme Court in September 2021, the Corps continues to conduct the review, which is estimated to be completed in the spring of 2023, following a pause on its work in 2022. Once the review is completed, the Corps will determine whether DAPL is safe to operate or must be shut down. There has not been any decision on whether the U.S. Supreme Court will hear the appeal and we are unable to determine the outcome or the impact on DAPL in the future.
We utilize DAPL to transport a portion of our Bakken crude oil production to ultimate markets on the U.S. gulf coast. Our transportation commitment on the pipeline totals 30,000 barrels per day which will continue through February 2026 at which time the commitment decreases to 26,450 barrels per day through July 2028.
If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly. A restriction of DAPL's takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on acceptable terms, which could lead to a decline in our crude oil and natural gas reserves, production and revenues. In addition, funding our capital expenditures with additional debt will increase our leverage and doing so with equity securities may result in dilution that reduces the value of your stock.
The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. We have budgeted $2.30 billion for capital expenditures in 2018 (excluding acquisitions which are not budgeted) of which $1.99 billion is allocated for explorationmonitor and development drilling. We may adjust our 2018 capital spending plans upward or downward depending on market conditions.
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If oil and gas industry conditions weaken as a result of low commodity prices or other factors, our abilitywe may not be able to borrow may decreasegenerate sufficient cash flows and we may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. Currently, weA decline in cash flows from operations may require us to revise our capital program or seek financing in banking or capital markets to fund our operations.
We have a revolving credit facility with lender commitments totaling $2.75$2.255 billion that matures in May 2019.October 2026. In the future, we may not be able to access adequate funding under our revolving credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments under the credit facility. Our lenders could decline to increase their commitments based on our financial condition, the financial condition of our industry or the economy as a whole or for other reasons beyond our control. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or on terms we find acceptable. If operating cash flows are insufficient and we are unable to access funding or execute capital transactions when needed on acceptable terms, we may not be able to fully implement our business plans, fund our capital program and commitments, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The unavailability or high cost of drilling rigs, well completion crews, water, equipment, supplies, personnel and oilfieldfield services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.
In the regions in which we operate, there have historically been shortages of drilling rigs, well completion crews, equipment, supplies, personnel, or oilfieldfield services, and supplies, including key components used in fracture stimulation processes such as water and proppants, as well as high costs associated with these critical components of our operations. With current technology, water is an essential component of drilling and hydraulic fracturing processes. The availability of water sources and disposal facilities is becoming increasingly competitive, constrained, subject to social and regulatory scrutiny, and impacted by third-party supply chains over which we may have limited control. Limitations or restrictions on our ability to secure, transport, and use sufficient amounts of water, including limitations resulting from natural causes such as drought, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling or completion sites, resulting in increased costs.
The demand for qualified and experienced oilfieldfield service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices or supply chain disruptions, causing periodic shortages.
We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in new or emerging areas are more uncertain than drilling results in developed and producing areas. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage willin the emerging areas may decline if drilling results are unsuccessful.
Our business operations, financial position, results of operations, and cash flows have been and may in the future be materially and adversely affected by the COVID-19 pandemic.
The initial outbreak of COVID-19 negatively impacted the global economy and led to, among other things, reduced global demand for crude oil, disruption of global supply chains, and significant volatility and disruption of financial and commodity markets. In response to the initial outbreak of COVID-19, many state and local jurisdictions imposed quarantines and restrictions on their residents to control the spread of COVID-19. Such quarantines and restrictions resulted in business closures, work stoppages, slowdowns and delays, work-from-home policies, travel restrictions and cancellation of events, among other effects. During 2021 and 2022, the distribution of
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COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. While the prices of and demand for crude oil have recovered, further outbreaks, or the emergence of new strains of the COVID-19 virus, could result in the reimposition of domestic and international regulations directing individuals to stay at home, limiting travel, requiring facility closures and imposing quarantines. Widespread implementation of these or similar restrictions could result in commodity price volatility and reduced demand for crude oil and natural gas, which could materially and adversely affect our financial position and results of operations.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2022, non-operated properties represented 14% of our estimated proved developed reserves, 9% of our estimated proved undeveloped reserves, and 12% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including the marketing of oil and gas production, compliance with environmental, occupational safety and health and other regulations, or the amount of expenditures required to fund the development and operation of such properties. Moreover, we are dependent on other working interest owners on these projects to fund their contractual share of capital and operating expenditures. These limitations and our dependence on the operators and other working interest owners for these projects could cause us to incur unexpected future costs and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may be subject to risks in connection with acquisitions, divestitures, and joint development arrangements.
As part of our business strategy, we have made and will likelyexpect to continue to makemaking acquisitions of oil and gas properties, divest of non-strategic assets, and enter into joint development arrangements. Suitable acquisition properties, buyers of our non-strategic assets, or joint development counterparties may not be available on terms and conditions we find acceptable or not at all.
The accuracy of these acquisition assessments is inherently uncertain. In connection with these assessments, we perform a review, which we believe to be generally consistent with industry practices, of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every well,property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller
As a result of our strategy of assessing and executing on accretive acquisitions, the size and geographic footprint of our business has increased and may continue to do so, including into new jurisdictions. Our future success will depend, in part, on our ability to manage our expanded business, which may pose challenges including those related to the management and monitoring of new operations and basins and associated increased costs and complexity. We believe our acquisitions will complement our business strategies by delivering enhanced free cash flows and corporate returns, among other things. However, the anticipated benefits of the transactions may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and
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realize the anticipated benefits within anticipated timing or at all, our business, financial condition and operating results may be adversely affected.
In addition, from time to time we may sell or otherwise dispose of certain non-strategic assets as a result of an evaluation of our asset portfolio or to provide cash flow for use in reducing debt and enhancing liquidity. Such divestitures have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets, and potential post-closing adjustments and claims for indemnification. Additionally, volatility and unpredictability in commodity prices may result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to closing.
Volatility in the financial markets or in global economic conditions, including consequences resulting from domestic political uncertainty, geopolitical events, international trade disputes and tariffs, and health epidemics could adversely impact our business.
United States and global economies may experience periods of volatility and uncertainty from time to time, resulting in unstable consumer confidence, diminished consumer demand and spending, diminished liquidity and credit availability, and inability to access capital markets. In recent years, certain global economies have experienced periods of political uncertainty, slowing economic growth, rising interest rates, inflation, changing economic sanctions, health-related concerns, and currency volatility. These global macroeconomic conditions may have a negative impact on commodity prices and the availability and cost of materials used in our industry, which in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In recent years, the United States government has initiated new tariffs on certain imported goods and has imposed increases to certain existing tariffs on imported goods. In response, certain foreign governments, most notably China, imposed retaliatory tariffs on certain goods their countries import from the United States. These and other events, including the United Kingdom's withdrawal from the European Union and the COVID-19 pandemic, have contributed to increased uncertainty for domestic and global economies. Additionally, growing trends toward populism and political polarization globally and in the U.S. have resulted in uncertainty regarding potential changes in regulations, fiscal policy, social programs, domestic and foreign relations, and government energy policies, which could pose a potential threat to domestic and global economic growth.
Trade restrictions or other governmental actions related to tariffs or trade policies have impacted, and have the potential to further impact, our business and industry by increasing the cost of materials used in various aspects of upstream, midstream, and downstream oil and gas activities. Furthermore, tariffs and any quantitative import restrictions, particularly those impacting the cost and availability of steel and aluminum, may cause disruption in the energy industry's supply chain, resulting in the delay or cessation of drilling and completion efforts or the postponement or cancellation of new pipeline transportation projects the U.S. industry is relying on to transport its onshore production to market, as well as endangering U.S. liquefied natural gas export projects resulting in negative impacts on natural gas production. Additionally, trade and/or tariff disputes have impacted, and have the potential to further impact, domestic and global economies overall, which could result in reduced demand for crude oil and natural gas. Any of the above consequences could have a material adverse effect on our business, financial condition, results of operations and cash flows.
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
Our business and industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We rely heavily on digital technologies, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. The availability and integrity of these systems are essential for us to conduct our operations. Our business associates, including employees, vendors, service providers, financial institutions, and transporters, processors, and purchasers of our production are also heavily dependent on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks, and those of our business associates have been and continue to be the target of cyber attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release or theft of confidential or protected information, corruption of data or other disruptions of our business operations. For example, there have been well-publicized cases in recent years involving cyber attacks on software vendors utilized by the Company. In response to those incidents, we deployed our cybersecurity incidence response protocols and promptly took steps to contain and remediate potential vulnerabilities. We believe there have been no compromises to our operations as a result of the attacks; however, other similar attacks in the future could have a significant negative impact on our systems and operations.
A cyber attack involving our information systems and related infrastructure, and/or that of our business associates and customers, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to unauthorized access
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to, or theft of, sensitive or proprietary information and data corruption or operational disruption that adversely affects our ability to carry on our business. Any such event could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability, which could have a material adverse effect on our business, financial condition, results of operations or cash flows. In addition, certain cyber incidents such as reconnaissance of our systems and those of our business associates, may remain undetected for an extended period, which could result in significant consequences. We do not maintain specialized insurance for possible liability resulting from cyber attacks due to lack of coverage for what we consider sensitive and proprietary data.
While the Company has well-established cyber security systems and controls, disclosure controls and procedures and incident response protocols, these systems, controls, procedures and protocols may not identify all risks and threats we face, or may fail to protect data or mitigate the adverse effects of data loss.
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 a breach of our systems or those of our business associates. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which may impose significant costs that are likely to increase over time.
Competition in the crude oil and natural gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.
Our ability to acquire additional prospects and find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, securing long-term transportation and processing capacity, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our inability to effectively compete in this environment could have a material adverse effect on our financial condition, results of operations and cash flows.
Severe weather events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Severe weather events and natural disasters such as hurricanes, tornadoes, seismic events, floods, blizzards, extreme cold, drought, and ice storms affecting the areas in which we operate, including our corporate headquarters, could cause disruptions and in some cases suspension of our or our third party service providers' operations, which could have a material adverse effect on our business. Our planning for normal climatic variation, natural disasters, insurance programs and emergency recovery plans may inadequately mitigate the effects of such climatic conditions, and not all such effects can be predicted, eliminated or insured against. Longer term changes in temperature and precipitation patterns may result in changes to the amount, timing, or location of demand for energy or our production. While we consider these factors in our disaster preparedness and response and business continuity planning, we may not consider or prepare for every eventuality in such planning.
Financial Risks
Our revolving credit facility, term loan, and indentures for our senior notes contain certain covenants and restrictions, the violation of which could adversely affect our business, financial condition and results of operations.
Our revolving credit facility and term loan contain restrictive covenants with which we must comply, including covenants that limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, and merge, consolidate or sell all or substantially all of our assets. Our revolving credit facility and term loan also contain a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders' equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. At December 31, 2022, we had $1.16 billion of outstanding borrowings on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.50.
The indentures governing our senior notes contain covenants that, among other things, limit our ability to create liens securing certain indebtedness, enter into certain sale and leaseback transactions, and consolidate, merge or transfer certain assets.
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Our ability to comply with the provisions of our revolving credit facility, term loan or senior note indentures may be impacted by changes in economic or business conditions, results of operations, or events beyond our control. The breach of any covenant could result in a default under our revolving credit facility, term loan or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, could result in all amounts outstanding thereunder, together with accrued interest, to be due and payable. If our indebtedness is accelerated, our assets may not be sufficient to repay in full such indebtedness, which would have a material adverse effect our business, financial condition, results of operations, and cash flows.
The inability of joint interest owners, significant customers, and service providers to meet their obligations to us may adversely affect our financial results.
Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.3 billion in receivables at December 31, 2022) and our joint interest and other receivables ($458 million at December 31, 2022). These counterparties may experience insolvency or liquidity issues and may not be able to meet their obligations and liabilities owed to us, particularly during a period of depressed commodity prices. Defaults by these counterparties could adversely impact our financial condition and results of operations.
Additionally, we rely on field service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A worsening of the commodity price environment may result in a material adverse impact on the liquidity and financial position of the parties with whom we do business, resulting in delays in payment of, or non-payment of, amounts owed to us, delays in operations, loss of access to equipment and facilities and similar impacts. These events could have an adverse impact on our business, financial condition, results of operations and cash flows.
Legal and Regulatory Risks
Laws, regulations, guidance, executive actions or other regulatory initiatives regarding environmental protection and occupational safety and health could increase our costs of doing business and result in operating restrictions, delays, or cancellations in the drilling and completion of crude oil and natural gas wells, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Our crude oil and natural gas exploration and production operations are subject to stringent federal, state and local legal requirements governing environmental protection and occupational safety and health. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of certain environmental and occupational safety and health legal requirements that govern us, including with respect to air emissions, including natural gas flaring limitations and ozone standards; climate change, including restriction of methane or other greenhouse gas emissions and suspensions of, or more stringent limitations upon, new leasing and permitting on federal lands and waters; hydraulic fracturing; waste water disposal regulatory developments; occupational safety standards, and other risks or regulations relating to environmental protection. One or more of these legal requirements could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We are subject to certain complex federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health that could result in increased costs, operating restrictions or delays, limitations or prohibitions on our ability to develop and produce reserves, or expose us to significant liabilities.
Our crude oil and natural gas exploration and production operations are subject to complex and stringent federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health, including with respect to production, sales and transport of crude oil, NGLs and natural gas, employees and labor relations, and taxation. For instance, President Biden's administration has pursued, and may continue to pursue, legislative changes to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and gas exploration and production companies, including: (i) the elimination of deductions for intangible drilling and exploration and development costs; (ii) a repeal of the percentage depletion allowance for crude oil and natural gas properties; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is uncertain whether these or other changes being pursued will be enacted or, if enacted, how soon any such changes would become effective.
Additionally, in August 2022 President Biden signed the Inflation Reduction Act of 2022 (“IRA”) into law, which provides various new tax provisions, incentives, and tax credits aimed at curbing inflation by lowering prescription drug costs, health care costs, and energy costs. The IRA introduces, among other things, (i) a 15% corporate alternative minimum tax on profits for corporations whose average annual adjusted financial statement income for any consecutive three-year period ending after December 31, 2021 exceeds $1
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billion and (ii) a methane emissions charge, effective January 1, 2024, on specific types of oil and gas production facilities that report emissions in excess of applicable thresholds.
Failure to comply with the above and other laws and regulations, including those described in Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry, may trigger a variety of administrative, civil and criminal enforcement investigations or actions, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations, criminal sanctions, or litigation. Moreover, changes to existing laws or regulations or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products. Similarly, changes in regulatory policies and priorities could result in the imposition of new laws or regulations that adversely impact us or our industry. Any such changes could increase our operating costs, delay our operations or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Our operations and the operations of our customers are subject to a number of risks arising out of the threat of terrorist attacks, whether domesticclimate change, energy conservation measures, or foreign attacks, as well as military or other actions takeninitiatives that stimulate demand for alternative forms of energy that could result in response to these acts, could cause instabilityincreased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the global financialdemand for the crude oil and natural gas we produce.
Risks arising out of the threat of climate change, fuel conservation measures, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy markets. Continued hostilitiesgeneration devices may create new competitive conditions that result in reduced demand for the Middle Eastcrude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, variability in power generation output from alternative energy facilities that are dependent on weather conditions, such as wind and solar, may result in intermittent changes in demand for the occurrence or threat of terrorist attacks in the United States or other countriescommodities we produce which could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets,lead to increased volatility in commodity pricesprices. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion relating to risks arising out of the threat of climate change and emission of greenhouse gases, climate change activism, energy conservation measures, initiatives that stimulate demand for alternative forms of energy, and physical effects of climate change. One or the possibility that infrastructuremore of these developments could have an adverse effect on our assets and operations.
Increasing scrutiny on environmental, social, and corporate governance matters may impact our business.
Companies across all industries are facing increasing scrutiny from a wide array of stakeholders related to their ESG practices. ESG standards are evolving and if we rely onare perceived to have not responded appropriately to certain standards, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business or financial condition, could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affected. Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential consumer use of alternative forms of energy may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our ability to recruit necessary talent, and our access to capital markets.
Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy companies or impose certain ESG-related targets or goals as a condition to funding. While we cannot predict what polices may result from these developments, such efforts could make it more difficult for fossil fuel companies to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or other aspects of our business and results of operations.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The information required by Item 2 is contained in
Part I, Item 1. Business—Crude Oil and Natural Gas Operations and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Delivery Commitments and is incorporated herein by reference.Item 3. Legal Proceedings
29
We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and Contingencies–Litigation in Part II, Item 8. Financial Statementssurface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and Supplementary Data–Notesother matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to Consolidated Financial Statements
Item 4. Mine Safety Disclosures
Not applicable.
30
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listedpreviously traded on the New York Stock Exchange and trades(“NYSE”) under the symbol “CLR.” As a result of the take-private transaction described in Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction, our common stock ceased to be listed on the NYSE effective November 23, 2022 and there is no longer an established trading market for our common stock.
The following table sets forth quarterly high and low sales prices for each quarter of the previous two years. No cash dividends were declared during the previous two years.
2017 | 2016 | |||||||||||||||||||||||||||||||
Quarter Ended | Quarter Ended | |||||||||||||||||||||||||||||||
March 31 | June 30 | September 30 | December 31 | March 31 | June 30 | September 30 | December 31 | |||||||||||||||||||||||||
High | $ | 53.57 | $ | 47.87 | $ | 40.03 | $ | 53.55 | $ | 31.90 | $ | 46.01 | $ | 52.78 | $ | 60.30 | ||||||||||||||||
Low | $ | 41.28 | $ | 30.18 | $ | 29.08 | $ | 36.05 | $ | 13.94 | $ | 28.63 | $ | 40.92 | $ | 44.37 | ||||||||||||||||
Cash Dividend | — | — | — | — | — | — | — | — |
Period |
| Total number of shares purchased |
|
| Average price paid per share |
|
| Total number of shares purchased as part of publicly announced plans or programs (1) |
|
| Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (1) |
| ||||
October 1, 2022 to October 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Repurchases for tax withholdings (1) |
|
| 20,081 |
|
| $ | 68.22 |
|
|
| — |
|
| $ | — |
|
November 1, 2022 to November 30, 2022 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Repurchases for tax withholdings (1) |
|
| 2,499 |
|
| $ | 74.07 |
|
|
| — |
|
| $ | — |
|
Take-private transaction (2) |
|
| 58,059,259 |
|
| $ | 74.28 |
|
|
| — |
|
| $ | — |
|
Total for the quarter |
|
| 58,081,839 |
|
| $ | 74.28 |
|
|
|
|
|
|
|
Period | Total number of shares purchased (1) | Average price paid per share (2) | Total number of shares purchased as part of publicly announced plans or programs | Maximum number of shares that may yet be purchased under the plans or programs | |||||||||
October 1, 2017 to October 31, 2017 | 234 | $ | 38.24 | — | — | ||||||||
November 1, 2017 to November 30, 2017 | 18,435 | $ | 44.84 | — | — | ||||||||
December 1, 2017 to December 31, 2017 | — | — | — | — | |||||||||
Total | 18,669 | $ | 44.76 | — | — |
Amounts represent shares surrendered by employees to cover tax liabilities in connection with the vesting of restricted stock granted under the Company's 2013 Long-Term Incentive Plan. We paid the associated taxes to the applicable taxing authorities. The price paid per share was the closing price of |
Item 6. Reserved
31
Table of December 31, 2012 through December 31, 2017. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, 2012 and that any dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.The information provided in this section is being furnished to, and not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.
Year Ended December 31, | ||||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
Income Statement data | ||||||||||||||||||||
In thousands, except per share data | ||||||||||||||||||||
Crude oil and natural gas sales | $ | 2,982,966 | $ | 2,026,958 | $ | 2,552,531 | $ | 4,203,022 | $ | 3,573,431 | ||||||||||
Gain (loss) on crude oil and natural gas derivatives, net (1) | 91,647 | (71,859 | ) | 91,085 | 559,759 | (191,751 | ) | |||||||||||||
Total revenues | 3,120,828 | 1,980,273 | 2,680,167 | 4,801,618 | 3,421,807 | |||||||||||||||
Income (loss) from continuing operations (2) | 789,447 | (399,679 | ) | (353,668 | ) | 977,341 | 764,219 | |||||||||||||
Net income (loss) (2) | 789,447 | (399,679 | ) | (353,668 | ) | 977,341 | 764,219 | |||||||||||||
Basic net income (loss) per share: | ||||||||||||||||||||
From continuing operations | $ | 2.13 | $ | (1.08 | ) | $ | (0.96 | ) | $ | 2.65 | $ | 2.08 | ||||||||
Net income (loss) per share | $ | 2.13 | $ | (1.08 | ) | $ | (0.96 | ) | $ | 2.65 | $ | 2.08 | ||||||||
Shares used in basic income (loss) per share | 371,066 | 370,380 | 369,540 | 368,829 | 368,150 | |||||||||||||||
Diluted net income (loss) per share: | ||||||||||||||||||||
From continuing operations | $ | 2.11 | $ | (1.08 | ) | $ | (0.96 | ) | $ | 2.64 | $ | 2.07 | ||||||||
Net income (loss) per share | $ | 2.11 | $ | (1.08 | ) | $ | (0.96 | ) | $ | 2.64 | $ | 2.07 | ||||||||
Shares used in diluted income (loss) per share | 373,768 | 370,380 | 369,540 | 370,758 | 369,698 | |||||||||||||||
Production volumes | ||||||||||||||||||||
Crude oil (MBbl) (3) | 50,536 | 46,850 | 53,517 | 44,530 | 34,989 | |||||||||||||||
Natural gas (MMcf) | 228,159 | 195,240 | 164,454 | 114,295 | 87,730 | |||||||||||||||
Crude oil equivalents (MBoe) | 88,562 | 79,390 | 80,926 | 63,579 | 49,610 | |||||||||||||||
Sales volumes | ||||||||||||||||||||
Crude oil (MBbl) (3) | 50,628 | 46,802 | 53,664 | 44,122 | 34,985 | |||||||||||||||
Natural gas (MMcf) | 228,159 | 195,240 | 164,454 | 114,295 | 87,730 | |||||||||||||||
Crude oil equivalents (MBoe) | 88,655 | 79,342 | 81,073 | 63,172 | 49,607 | |||||||||||||||
Average sales prices (4) | ||||||||||||||||||||
Crude oil ($/Bbl) | $ | 45.70 | $ | 35.51 | $ | 40.50 | $ | 81.26 | $ | 89.93 | ||||||||||
Natural gas ($/Mcf) | $ | 2.93 | $ | 1.87 | $ | 2.31 | $ | 5.40 | $ | 4.87 | ||||||||||
Crude oil equivalents ($/Boe) | $ | 33.65 | $ | 25.55 | $ | 31.48 | $ | 66.53 | $ | 72.04 | ||||||||||
Average costs per unit (4) | ||||||||||||||||||||
Production expenses ($/Boe) | $ | 3.66 | $ | 3.65 | $ | 4.30 | $ | 5.58 | $ | 5.69 | ||||||||||
Production taxes (% of oil and gas revenues) | 7.0 | % | 7.0 | % | 7.8 | % | 8.2 | % | 8.3 | % | ||||||||||
DD&A ($/Boe) | $ | 18.89 | $ | 21.54 | $ | 21.57 | $ | 21.51 | $ | 19.47 | ||||||||||
General and administrative expenses ($/Boe) (5) | $ | 2.16 | $ | 2.14 | $ | 2.34 | $ | 2.92 | $ | 2.91 | ||||||||||
Proved reserves at December 31 | ||||||||||||||||||||
Crude oil (MBbl) | 640,949 | 643,228 | 700,514 | 866,360 | 737,788 | |||||||||||||||
Natural gas (MMcf) | 4,140,281 | 3,789,818 | 3,151,786 | 2,908,386 | 2,078,020 | |||||||||||||||
Crude oil equivalents (MBoe) | 1,330,995 | 1,274,864 | 1,225,811 | 1,351,091 | 1,084,125 | |||||||||||||||
Other financial data (in thousands) | ||||||||||||||||||||
Net cash provided by operating activities | $ | 2,079,106 | $ | 1,125,919 | $ | 1,857,101 | $ | 3,355,715 | $ | 2,563,295 | ||||||||||
Net cash used in investing activities | $ | (1,808,845 | ) | $ | (532,965 | ) | $ | (3,046,247 | ) | $ | (4,587,399 | ) | $ | (3,711,011 | ) | |||||
Net cash (used in) provided by financing activities | $ | (243,034 | ) | $ | (587,773 | ) | $ | 1,187,189 | $ | 1,227,715 | $ | 1,140,469 | ||||||||
Total capital expenditures | $ | 2,035,254 | $ | 1,110,256 | $ | 2,564,301 | $ | 5,015,595 | $ | 3,841,633 | ||||||||||
Balance Sheet data at December 31 (in thousands) | ||||||||||||||||||||
Total assets | $ | 14,199,651 | $ | 13,811,776 | $ | 14,919,808 | $ | 15,076,033 | $ | 11,841,567 | ||||||||||
Long-term debt, including current portion | $ | 6,353,691 | $ | 6,579,916 | $ | 7,117,788 | $ | 5,928,878 | $ | 4,650,889 | ||||||||||
Shareholders’ equity | $ | 5,131,203 | $ | 4,301,996 | $ | 4,668,900 | $ | 4,967,844 | $ | 3,953,118 |
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes as well as the selected consolidated financial data included elsewhere in this report. Our operatingResults attributable to noncontrolling interests are not material relative to consolidated results for the periodsand are not separately presented or discussed below may not be indicative of future performance. For additional discussion of crude oil and natural gas reserve information, please see
The following discussion and analysis includes forward-looking statements and should be read in conjunction with
Part I, Item 1A. Risk Factors in this report, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.Overview
We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas.gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil, natural gas, and natural gas liquids and expect this to continue in the future. Our operations are primarily focusedcorporate internet website is www.clr.com.
Take-private transaction
On October 16, 2022, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Pursuant to the Merger Agreement, on explorationNovember 22, 2022 Merger Sub completed a tender offer to purchase any and development activitiesall of the outstanding shares of the Company’s common stock for $74.28 per share in cash, other than: (i) shares of common stock owned by Mr. Hamm, certain of his family members and their affiliated entities (collectively, the Bakken field“Hamm Family”) and (ii) shares of North Dakotacommon stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans. Immediately prior to the consummation of the Offer, Mr. Hamm contributed 100% of the capital stock of Merger Sub to the Company, as a result of which Merger Sub became a wholly owned subsidiary of the Company. Following consummation of the Offer, Merger Sub merged with and Montanainto the Company, with the Company continuing as the surviving corporation wholly owned by the Hamm Family.
Following the completion of the transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (ii) our common stock was deregistered under Section 12(b) of the Securities Exchange Act of 1934 as amended (the “Exchange Act”), and (iii) we suspended our reporting obligations under Section 15(d) of the SCOOPExchange Act. As a result, certain of the corporate governance, disclosure, and STACK areasother provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer apply to us. We will continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures.
See Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Oklahoma.
Financial and Outlook
Commodity prices remained volatile during the year, but generally increased on averagesignificantly in 2017 relative2022 compared to 2016. Crude oil prices in particular showed significant signs of improvement in late 2017 and early 2018, with West Texas Intermediate crude oil benchmark prices reaching a three-year high of $66 per barrel in January 2018. With our portfolio of high quality assets, we are well-positioned to manage2021 levels resulting from the ongoing challenges and price volatility facing our industry.
The following table contains financial and operating highlights for the periods presented. Average net sales prices exclude any effect of 18%derivative transactions. Per-unit expenses have been calculated using sales volumes.
32
|
| Year ended December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Average daily production: |
|
|
|
|
|
|
|
|
| |||
Crude oil (Bbl per day) |
|
| 199,526 |
|
|
| 160,647 |
|
|
| 160,505 |
|
Natural gas (Mcf per day) (1) |
|
| 1,213,643 |
|
|
| 1,014,000 |
|
|
| 837,509 |
|
Crude oil equivalents (Boe per day) |
|
| 401,800 |
|
|
| 329,647 |
|
|
| 300,090 |
|
Average net sales prices (2): |
|
|
|
|
|
|
|
|
| |||
Crude oil ($/Bbl) |
| $ | 91.46 |
|
| $ | 64.06 |
|
| $ | 34.71 |
|
Natural gas ($/Mcf) (1) |
| $ | 7.01 |
|
| $ | 4.88 |
|
| $ | 1.04 |
|
Crude oil equivalents ($/Boe) |
| $ | 66.58 |
|
| $ | 46.24 |
|
| $ | 21.47 |
|
Crude oil net sales price discount to NYMEX ($/Bbl) |
| $ | (2.71 | ) |
| $ | (4.00 | ) |
| $ | (5.80 | ) |
Natural gas net sales price premium (discount) to NYMEX ($/Mcf) |
| $ | 0.29 |
|
| $ | 1.00 |
|
| $ | (1.10 | ) |
Production expenses ($/Boe) |
| $ | 4.24 |
|
| $ | 3.38 |
|
| $ | 3.27 |
|
Production taxes (% of net crude oil and natural gas sales) |
|
| 7.5 | % |
|
| 7.3 | % |
|
| 8.2 | % |
DD&A ($/Boe) |
| $ | 12.86 |
|
| $ | 15.76 |
|
| $ | 17.12 |
|
Total general and administrative expenses ($/Boe) |
| $ | 2.74 |
|
| $ | 1.94 |
|
| $ | 1.79 |
|
Results of Operations
The following table presents selected financial and operating information for the periods presented.
|
| Year Ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Crude oil, natural gas, and natural gas liquids sales |
| $ | 10,074,675 |
|
| $ | 5,793,741 |
|
| $ | 2,555,434 |
|
Loss on derivative instruments, net |
|
| (671,095 | ) |
|
| (128,864 | ) |
|
| (14,658 | ) |
Crude oil and natural gas service operations |
|
| 70,128 |
|
|
| 54,441 |
|
|
| 45,694 |
|
Total revenues |
|
| 9,473,708 |
|
|
| 5,719,318 |
|
|
| 2,586,470 |
|
Operating costs and expenses |
|
| (4,120,028 | ) |
|
| (3,257,638 | ) |
|
| (3,140,362 | ) |
Other expenses, net |
|
| (285,267 | ) |
|
| (275,542 | ) |
|
| (220,859 | ) |
Income (loss) before income taxes |
|
| 5,068,413 |
|
|
| 2,186,138 |
|
|
| (774,751 | ) |
(Provision) benefit for income taxes |
|
| (1,020,804 | ) |
|
| (519,730 | ) |
|
| 169,190 |
|
Income (loss) before equity in net loss of affiliate |
|
| 4,047,609 |
|
|
| 1,666,408 |
|
|
| (605,561 | ) |
Equity in net loss of affiliate |
|
| (1,489 | ) |
|
| — |
|
|
| — |
|
Net income (loss) |
|
| 4,046,120 |
|
|
| 1,666,408 |
|
|
| (605,561 | ) |
Net income (loss) attributable to noncontrolling interests |
|
| 21,562 |
|
|
| 5,440 |
|
|
| (8,692 | ) |
Net income (loss) attributable to Continental Resources |
| $ | 4,024,558 |
|
| $ | 1,660,968 |
|
| $ | (596,869 | ) |
|
|
|
|
|
|
|
|
|
| |||
Production volumes: |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 72,827 |
|
|
| 58,636 |
|
|
| 58,745 |
|
Natural gas (MMcf) |
|
| 442,980 |
|
|
| 370,110 |
|
|
| 306,528 |
|
Crude oil equivalents (MBoe) |
|
| 146,657 |
|
|
| 120,321 |
|
|
| 109,833 |
|
Sales volumes: |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 72,732 |
|
|
| 58,757 |
|
|
| 58,793 |
|
Natural gas (MMcf) |
|
| 442,980 |
|
|
| 370,110 |
|
|
| 306,528 |
|
Crude oil equivalents (MBoe) |
|
| 146,562 |
|
|
| 120,442 |
|
|
| 109,881 |
|
33
Year ended December 31, 2022 compared to the third quarteryear ended December 31, 2021
Below is a discussion of 2017 and 37% higher than the fourth quarterchanges in our results of 2016.
Production
The following table summarizes the changes in our average daily Boe production by major operating area for the periods presented.
|
| Fourth Quarter |
|
| Year Ended December 31, |
| ||||||||||||||||||
Boe production per day |
| 2022 |
|
| 2021 |
|
| % Change |
|
| 2022 |
|
| 2021 |
|
| % Change |
| ||||||
Bakken |
|
| 174,397 |
|
|
| 175,585 |
|
|
| (1 | )% |
|
| 171,025 |
|
|
| 169,636 |
|
|
| 1 | % |
Anadarko Basin |
|
| 165,225 |
|
|
| 146,131 |
|
|
| 13 | % |
|
| 158,221 |
|
|
| 147,249 |
|
|
| 7 | % |
Powder River Basin |
|
| 28,057 |
|
|
| 7,189 |
|
|
| 290 | % |
|
| 24,602 |
|
|
| 5,161 |
|
|
| 377 | % |
Permian Basin (1) |
|
| 44,925 |
|
|
| 4,997 |
|
|
| - |
|
|
| 41,917 |
|
|
| 1,260 |
|
|
| - |
|
All other |
|
| 5,552 |
|
|
| 6,266 |
|
|
| (11 | )% |
|
| 6,035 |
|
|
| 6,341 |
|
|
| (5 | )% |
Total |
|
| 418,156 |
|
|
| 340,168 |
|
|
| 23 | % |
|
| 401,800 |
|
|
| 329,647 |
|
|
| 22 | % |
Fourth Quarter | Year Ended December 31, | |||||||||||||||||
Boe production per day | 2017 | 2016 | % Change | 2017 | 2016 | % Change | ||||||||||||
Bakken | 165,598 | 104,524 | 58 | % | 132,992 | 119,200 | 12 | % | ||||||||||
SCOOP | 62,242 | 63,490 | (2 | %) | 60,693 | 65,062 | (7 | %) | ||||||||||
STACK | 47,914 | 24,426 | 96 | % | 36,220 | 16,983 | 113 | % | ||||||||||
All other | 11,231 | 17,421 | (36 | %) | 12,732 | 15,667 | (19 | %) | ||||||||||
Total | 286,985 | 209,861 | 37 | % | 242,637 | 216,912 | 12 | % |
December 31, 2017 | December 31, 2016 | Volume change | Volume percent change | |||||||||||||||
Proved reserves by area | MBoe | Percent | MBoe | Percent | ||||||||||||||
Bakken | 635,521 | 48 | % | 591,901 | 46 | % | 43,620 | 7 | % | |||||||||
SCOOP | 491,776 | 37 | % | 471,921 | 37 | % | 19,855 | 4 | % | |||||||||
STACK | 167,390 | 13 | % | 161,243 | 13 | % | 6,147 | 4 | % | |||||||||
All Other | 36,308 | 2 | % | 49,799 | 4 | % | (13,491 | ) | (27 | %) | ||||||||
Total | 1,330,995 | 100 | % | 1,274,864 | 100 | % | 56,131 | 4 | % |
Year ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
Average daily production: | ||||||||||||
Crude oil (Bbl per day) | 138,455 | 128,005 | 146,622 | |||||||||
Natural gas (Mcf per day) | 625,093 | 533,442 | 450,558 | |||||||||
Crude oil equivalents (Boe per day) | 242,637 | 216,912 | 221,715 | |||||||||
Average sales prices: | ||||||||||||
Crude oil ($/Bbl) | $ | 45.70 | $ | 35.51 | $ | 40.50 | ||||||
Natural gas ($/Mcf) | $ | 2.93 | $ | 1.87 | $ | 2.31 | ||||||
Crude oil equivalents ($/Boe) | $ | 33.65 | $ | 25.55 | $ | 31.48 | ||||||
Crude oil sales price discount to NYMEX ($/Bbl) | $ | (5.50 | ) | $ | (7.33 | ) | $ | (8.33 | ) | |||
Natural gas sales price discount to NYMEX ($/Mcf) | $ | (0.16 | ) | $ | (0.61 | ) | $ | (0.34 | ) | |||
Production expenses ($/Boe) | $ | 3.66 | $ | 3.65 | $ | 4.30 | ||||||
Production taxes (% of oil and gas revenues) | 7.0 | % | 7.0 | % | 7.8 | % | ||||||
DD&A ($/Boe) | $ | 18.89 | $ | 21.54 | $ | 21.57 | ||||||
Total general and administrative expenses ($/Boe) | $ | 2.16 | $ | 2.14 | $ | 2.34 |
Year Ended December 31, | ||||||||||||
In thousands, except sales price data | 2017 | 2016 | 2015 | |||||||||
Crude oil and natural gas sales | $ | 2,982,966 | $ | 2,026,958 | $ | 2,552,531 | ||||||
Gain (loss) on crude oil and natural gas derivatives, net | 91,647 | (71,859 | ) | 91,085 | ||||||||
Crude oil and natural gas service operations | 46,215 | 25,174 | 36,551 | |||||||||
Total revenues | 3,120,828 | 1,980,273 | 2,680,167 | |||||||||
Operating costs and expenses (1) | (2,671,427 | ) | (2,267,807 | ) | (2,904,168 | ) | ||||||
Other expenses, net (2) | (293,334 | ) | (344,920 | ) | (311,084 | ) | ||||||
Income (loss) before income taxes | 156,067 | (632,454 | ) | (535,085 | ) | |||||||
Benefit for income taxes (3) | 633,380 | 232,775 | 181,417 | |||||||||
Net income (loss) | $ | 789,447 | $ | (399,679 | ) | $ | (353,668 | ) | ||||
Diluted net income (loss) per share | $ | 2.11 | $ | (1.08 | ) | $ | (0.96 | ) | ||||
Production volumes: | ||||||||||||
Crude oil (MBbl) | 50,536 | 46,850 | 53,517 | |||||||||
Natural gas (MMcf) | 228,159 | 195,240 | 164,454 | |||||||||
Crude oil equivalents (MBoe) | 88,562 | 79,390 | 80,926 | |||||||||
Sales volumes: | ||||||||||||
Crude oil (MBbl) | 50,628 | 46,802 | 53,664 | |||||||||
Natural gas (MMcf) | 228,159 | 195,240 | 164,454 | |||||||||
Crude oil equivalents (MBoe) | 88,655 | 79,342 | 81,073 | |||||||||
Average sales prices: | ||||||||||||
Crude oil ($/Bbl) | $ | 45.70 | $ | 35.51 | $ | 40.50 | ||||||
Natural gas ($/Mcf) | $ | 2.93 | $ | 1.87 | $ | 2.31 | ||||||
Crude oil equivalents ($/Boe) | $ | 33.65 | $ | 25.55 | $ | 31.48 |
The following tables reflect our production by product and region for the periods presented.
Year Ended December 31, | Volume increase | Volume percent increase | ||||||||||||||||
2017 | 2016 | |||||||||||||||||
Volume | Percent | Volume | Percent | |||||||||||||||
Crude oil (MBbl) | 50,536 | 57 | % | 46,850 | 59 | % | 3,686 | 8 | % | |||||||||
Natural gas (MMcf) | 228,159 | 43 | % | 195,240 | 41 | % | 32,919 | 17 | % | |||||||||
Total (MBoe) | 88,562 | 100 | % | 79,390 | 100 | % | 9,172 | 12 | % |
Year Ended December 31, | Volume increase | Volume percent increase | ||||||||||||||||
2017 | 2016 | |||||||||||||||||
MBoe | Percent | MBoe | Percent | |||||||||||||||
North Region | 52,258 | 59 | % | 48,169 | 61 | % | 4,089 | 8 | % | |||||||||
South Region | 36,304 | 41 | % | 31,221 | 39 | % | 5,083 | 16 | % | |||||||||
Total | 88,562 | 100 | % | 79,390 | 100 | % | 9,172 | 12 | % |
|
| Year Ended December 31, |
|
|
|
|
| Volume |
| |||||||||||||||
|
| 2022 |
|
| 2021 |
|
| Volume |
|
| percent |
| ||||||||||||
|
| Volume |
|
| Percent |
|
| Volume |
|
| Percent |
|
| increase |
|
| increase |
| ||||||
Crude oil (MBbl) |
|
| 72,827 |
|
|
| 50 | % |
|
| 58,636 |
|
|
| 49 | % |
|
| 14,191 |
|
|
| 24 | % |
Natural gas (MMcf) |
|
| 442,980 |
|
|
| 50 | % |
|
| 370,110 |
|
|
| 51 | % |
|
| 72,870 |
|
|
| 20 | % |
Total (MBoe) |
|
| 146,657 |
|
|
| 100 | % |
|
| 120,321 |
|
|
| 100 | % |
|
| 26,336 |
|
|
| 22 | % |
The 8%24% increase in crude oil production in 20172022 compared to 20162021 was primarily driven by a 4,241 MBbls, or 13%, increaseour property acquisitions in production from propertiesthe Permian Basin and Powder River Basin over the past year and in North Dakota Bakken duelate 2021, which contributed to an increase in well completion activities, the timing ofour 2022 production commencing from new pad development projects,by 11,474 MBbls and strong initial production results being achieved on new wells resulting from optimized completion technologies. Additionally, production from our South region properties in the STACK play increased 1,6144,360 MBbls, or 104%, from the prior year duerespectively, compared to additional wells being completed and producing as a result of an increase in our drilling and completion activities in that area.2021. These increases were partially offset by decreaseda 1,373 MBbls, or 10%, decrease in Anadarko Basin crude oil production from our North region properties in Montana Bakken and the Red River units due to natural declinesa change in production coupled with reduced drilling activitiesallocation of capital from oil-weighted projects to gas-weighted projects in the play over the past year. Montana Bakken crude oil production decreased 692 MBbls, or 24%, while crude oil production inyear and the Red River units decreased 344 MBbls, or 9%, from the prior year. Additionally, crude oil production in SCOOP decreased 1,081 MBbls, or 16%, due to natural declines in production and limited drilling activities.
The 17%20% increase in natural gas production in 20172022 compared to 20162021 was driven by increased production from our propertiesdue in part to the previously described property acquisitions over the past year. Properties acquired in the STACK play duePermian Basin and new well completions increased our 2022 production by 20,191 MMcf while properties acquired in the Powder River Basin and new well completions increased our production by 16,415 MMcf compared to additional wells being completed and producing subsequent to December 31, 2016. Natural gas production in STACK increased 32,342 MMcf, or 116%, over the prior year.2021. Additionally, our natural gas production in North Dakota Bakkenthe Anadarko Basin increased 8,70032,264 MMcf, or 17%13%, over the prior year in conjunction with the aforementioned increase in crude oil production. These increases were partially offset by reduced production from our SCOOP properties, which decreased 3,469 MMcf, or 3%, along with various other areas in our North and South regions2022 compared to 2021 due to natural declines in production and limited drilling activities. Further, natural gas production decreased 1,323 MMcf in 2017 as a result of the sale of substantially all of our Arkoma Woodford properties in September 2017.
Revenues
Our revenues consist of sales of crude oil, natural gas, and natural gas liquids, gains and losses resulting from changes in the fair value of our crude oil and natural gas derivative instruments, and revenues associated with crude oil and natural gas service operations.
Net crude oil, natural gas, and natural gas sales.
Net crude oil, natural gas, and natural gas liquids sales. Net sales for 2017 were $2.982022 totaled $9.76 billion, a 47%75% increase fromcompared to net sales of $2.03$5.57 billion for 20162021 due to a 32% increasesignificant increases in realized commoditynet sales prices coupled with a 12% increase in totaland sales volumes.
Total sales volumes for 2022 increased 26,120 MBoe, or 22%, compared to 2021, primarily due to new wells added from our property acquisitions over the past year. For 2022, our crude oil sales volumes increased 24% compared to 2021 and our natural gas sales volumes increased 20% compared to 2021.
34
Our crude oil net sales prices averaged $45.70$91.46 per barrel for 2017,2022, an increase of 29%43% compared to $35.51$64.06 per barrel for 20162021 due to higher crude oilthe previously described increase in market prices andalong with improved price realizations.differentials. The differentialdiscount between NYMEX West Texas Intermediate (“WTI”) calendar month crude oil prices and our realized crude oil prices averaged $5.50 per barrel for 2017 compared to $7.33 for 2016. The improved differential was primarily due to improved realizations resulting from new pipeline takeaway capacity and additional markets becoming available in 2017 for Bakken production, along with the growth in our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma. These factors led to a continued improvement in crude oil price realizations throughout 2017. Our crude oil price differentials relative to WTInet sales prices improved to $4.23an average of $2.71 per barrel in the fourth quarter.
Our natural gas net sales prices averaged $2.93$7.01 per Mcf for 2017, a 57% increase2022 compared to $1.87$4.88 per Mcf for 20162021 due to higherthe previously described increase in market prices for natural gas and natural gas liquids (“NGLs”) and improved price realizations.prices. The discountdifference between our realized natural gasnet sales prices and NYMEX Henry Hub calendar month natural gas prices improved from $0.61was a premium of $0.29 per Mcf for 20162022 compared to $0.16a premium of $1.00 per Mcf for 2017.2021. The majority of our natural gas production is sold at our lease locations to midstream
Derivatives. The significant improvement in our pace of drilling and completion activities in 2017. For 2017, our crude oil sales volumes increased 8% compared to 2016 while our natural gas sales volumes increased 17%.
Crude oil and natural gas service operations.
Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities, which are impacted by our production volumes and theOperating Costs and Expenses
Production expenses
. Production expenses increasedProduction and ad valorem taxes.
Production and ad valorem taxes increasedYear ended December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Geological and geophysical costs | $ | 12,217 | $ | 12,106 | ||||
Exploratory dry hole costs | 176 | 4,866 | ||||||
Exploration expenses | $ | 12,393 | $ | 16,972 |
Depreciation, depletion, amortization and accretion (“DD&A”).
Total DD&AYear ended December 31, | ||||||||
$/Boe | 2017 | 2016 | ||||||
Crude oil and natural gas properties | $ | 18.57 | $ | 21.09 | ||||
Other equipment | 0.25 | 0.37 | ||||||
Asset retirement obligation accretion | 0.07 | 0.08 | ||||||
Depreciation, depletion, amortization and accretion | $ | 18.89 | $ | 21.54 |
|
| Year ended December 31, |
| |||||
$/Boe |
| 2022 |
|
| 2021 |
| ||
Crude oil and natural gas properties |
| $ | 12.57 |
|
| $ | 15.45 |
|
Other equipment |
|
| 0.20 |
|
|
| 0.22 |
|
Asset retirement obligation accretion |
|
| 0.09 |
|
|
| 0.09 |
|
Depreciation, depletion, amortization and accretion |
| $ | 12.86 |
|
| $ | 15.76 |
|
Estimated proved reserves are a key component in our computation of DD&A expense. Proved reserves are determined using the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months as required by SEC rules. Holding all other factors constant, if proved reserves are revised downward due to commodity price declines or other reasons, the rate at which we record DD&A expense increases. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense decreases. Upward revisions to
Our proved reserves have been revised upward over the past year dueprompted by significant increases in part to an improvement infirst-day-of-the-month commodity prices contributed toand other factors, which, when coupled with improvements in capital efficiency and strong well productivity, resulted in a decrease in our DD&A rate for crude oil and natural gas properties in 20172022 compared to 2016. Additionally, improvements2021 and helped offset the additional DD&A recognized in drilling efficiencies and optimized completion technologies over the past year have resulted in a significant improvement in the quantity2022 from increased sales volumes.
35
Property impairments.
Property impairmentsGeneral and administrative ("G&A") expenses.
Total G&A expenses include non-cash charges for equityequity/incentive compensation of
G&A expenses other than equity compensation included in the total G&A expense figure above totaled $145.8$183.8 million for 2017,2022, an increase of $24.3$13.4 million, or 20%8%, compared to $121.5$170.4 million for 2016. This increase was2021 primarily due to an increasethe growth of our operations and increases in payroll costs and employee compensation and benefits, in 2017 in response to the stabilization and improvement in commodity prices over the past year, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities over the prior period.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.
Year ended December 31, | ||||||||
$/Boe | 2017 | 2016 | ||||||
General and administrative expenses | $ | 1.64 | $ | 1.53 | ||||
Non-cash equity compensation | 0.52 | 0.61 | ||||||
Total general and administrative expenses | $ | 2.16 | $ | 2.14 |
|
| Year ended December 31, |
| |||||
$/Boe |
| 2022 |
|
| 2021 |
| ||
General and administrative expenses |
| $ | 1.25 |
|
| $ | 1.42 |
|
Non-cash equity/incentive compensation |
|
| 1.49 |
|
|
| 0.52 |
|
Total general and administrative expenses |
| $ | 2.74 |
|
| $ | 1.94 |
|
Transaction costs. We incurred $32 million of legal and advisory fees related to the Hamm Family's take-private transaction, which are included in the caption "Transaction costs" in the consolidated statements of income (loss) for 2022. In 2021, we incurred $14 million of transaction-related fees in connection with our December 2021 acquisition of properties in the Permian Basin.
Interest expense.
Interest expenseGain (loss) on extinguishment of an income tax benefit totaling approximately $713.7 million. Upon combining the tax benefit from this remeasurement with the tax provision recognized on pre-tax earnings from operations, we recognized a net total income tax benefit of $633.4 million for 2017.
Year Ended December 31, | Volume increase (decrease) | Volume percent increase (decrease) | ||||||||||||||||
2016 | 2015 | |||||||||||||||||
Volume | Percent | Volume | Percent | |||||||||||||||
Crude oil (MBbl) | 46,850 | 59 | % | 53,517 | 66 | % | (6,667 | ) | (12 | %) | ||||||||
Natural Gas (MMcf) | 195,240 | 41 | % | 164,454 | 34 | % | 30,786 | 19 | % | |||||||||
Total (MBoe) | 79,390 | 100 | % | 80,926 | 100 | % | (1,536 | ) | (2 | %) |
Year Ended December 31, | Volume increase (decrease) | Volume percent increase (decrease) | ||||||||||||||||
2016 | 2015 | |||||||||||||||||
MBoe | Percent | MBoe | Percent | |||||||||||||||
North Region | 48,169 | 61 | % | 54,956 | 68 | % | (6,787 | ) | (12 | %) | ||||||||
South Region | 31,221 | 39 | % | 25,970 | 32 | % | 5,251 | 20 | % | |||||||||
Total | 79,390 | 100 | % | 80,926 | 100 | % | (1,536 | ) | (2 | %) |
Year ended December 31, | ||||||||
In thousands | 2016 | 2015 | ||||||
Geological and geophysical costs | $ | 12,106 | $ | 11,032 | ||||
Exploratory dry hole costs | 4,866 | 8,381 | ||||||
Exploration expenses | $ | 16,972 | $ | 19,413 |
Year ended December 31, | ||||||||
$/Boe | 2016 | 2015 | ||||||
Crude oil and natural gas properties | $ | 21.09 | $ | 21.18 | ||||
Other equipment | 0.37 | 0.33 | ||||||
Asset retirement obligation accretion | 0.08 | 0.06 | ||||||
Depreciation, depletion, amortization and accretion | $ | 21.54 | $ | 21.57 |
Year ended December 31, | ||||||||
$/Boe | 2016 | 2015 | ||||||
General and administrative expenses | $ | 1.53 | $ | 1.70 | ||||
Non-cash equity compensation | 0.61 | 0.64 | ||||||
Total general and administrative expenses | $ | 2.14 | $ | 2.34 |
Income Taxes.
WeLiquidity and Capital Resources
Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our revolving credit facility and the issuance of debt securities. Additionally, in recent years non-strategic asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity.
As previously described, on November 22, 2022 the Hamm Family completed a tender offer to purchase any and all of the outstanding shares of the Company’s common stock for $74.28 per share in cash, other than: (i) shares of common stock owned by the Hamm Family and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans. A total of approximately 58.1 million shares of Continental’s common stock were purchased pursuant to the take-private transaction for total cash consideration of approximately $4.31 billion, inclusive of payments issued to holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law.
36
The purchase of outstanding shares was funded by Continental through the use of approximately $2.2 billion of cash on hand, $1.3 billion of credit facility borrowings, and the execution of a $750 million three-year term loan. As a result of the transaction, the Company’s leverage has increased and its liquidity has decreased. We intendremain committed to continue reducingoperating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our long-term debt using available cash flows from operations and/or proceeds from additional potential sales of non-strategic assets or through joint development arrangements; however, no assurance can be given that such transactions will occur.
At December 31, 2017,February 1, 2023, we had $43.9 million of cash and cash equivalents and approximately $2.56$1.12 billion of borrowing availability onunder our revolving credit facility after considering outstanding borrowings of $188 million and letters of credit. At
Based on our 2018planned capital expenditure budget,spending, our forecasted cash flows, and projected levels of indebtedness, we expect to maintain compliance with the covenants under our revolving credit facility, term loan, and senior note indentures for at least the next 12 months.indentures. Further, based on current market indications, we expect to meet in the ordinary course of business otherour contractual cash commitments to third parties pursuant to the various agreements subsequently described under the heading
Cash Flows
Cash flows from operating activities
Net cash provided by operating activities totaled $2.08increased $3.1 billion, and $1.13or 77%, to $7.04 billion for the years ended December 31, 2017 and 2016, respectively. The2022 compared to $3.97 billion for 2021 primarily due to a $4.28 billion increase in crude oil, natural gas, and NGL revenues due to the previously described increases in commodity prices and sales volumes in the current year. This increase was partially offset by a $308 million increase in realized cash losses on matured commodity derivatives, a $470 million increase in cash payments for U.S. federal income taxes, a $326 million increase in production and ad valorem taxes associated with higher revenues, and increases in certain other cash operating cash flows wasexpenses primarily due to an increase in crude oil and natural gas revenues driven by higher realized commodity prices and total sales volumes in 2017 coupled with lower interestand growth of our Company over the past year. Increased cash operating expenses the effects of which were partially offset by increasesincluded a $215 million increase in production expenses production taxes, and general and administrative expenses and a decrease$91 million increase in cash gains on matured natural gas derivatives.
Cash flows used in investing activities
Net cash flows used in investing activities totaled $3.53 billion and $4.99 billion for 2022 and 2021, respectively, the decrease of $1,808.8 million and $533.0 million, respectively. These totals include cash capital expenditureswhich reflects a reduction in the magnitude of $1,953.2 million and $1,164.5 million, respectively, inclusive of exploration and development drilling, property acquisitions and dry hole costs. Property acquisitions totaled $40.0 million and $35.9 million for the years ended December 31, 2017 and 2016, respectively. The increasebetween periods as discussed in capital spending was driven by an increase in our capital budget and related drilling and completion activities in 2017.
Cash flows from financing activities
Net cash used in financing activities for 2022 totaled $3.39 billion, primarily consisting of $4.3 billion of cash used to fund the year ended December 31, 2017Hamm Family's take-private transaction, $284 million of cash dividends paid on common stock, $100 million of cash used to repurchase shares of our common stock prior to the take-private transaction, and $32 million of cash used to repurchase senior notes. These cash outflows were partially offset by $660 million of net borrowings on our credit facility and $750 million of proceeds from the issuance of a new term loan to fund a portion of the take-private transaction.
Net cash provided by financing activities for 2021 totaled $243.0$989.1 million, primarily resulting from a reduction in total outstanding debt using available cash flows from operations and proceeds from asset dispositions. The $990 million$1.59 billion of net proceeds received from our December 2017November 2021 issuance of 2028 Notes were usedsenior notes and $340 million of net credit facility borrowings incurred to repay in full and terminate our $500 million term loan and to repayfund a portion of the borrowings outstanding under our revolving credit facility, thereby resulting in no significant net change in cash flows from financing activities related to these activities.
Future Sources of Financing
Although we cannot provide any assurance, we believe funds from operating cash flows, our remaining cash balance, and availability under our revolving credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, plannedbudgeted capital expenditures, and commitmentscash payments for income taxes for at least the next 12 months and to meet our contractual cash commitments to third parties described under the heading Future Capital Requirements beyond 12 months.
Based on current market indications, our budgeted capital expenditures budget has been established based on an expectation of availablespending plans for 2023 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows with any cash flow deficienciesrelative to budgeted spending are expected to be funded by borrowings under our revolving
37
credit facility or proceeds from asset sales or joint development arrangements.
We may choose to access thebanking or capital markets for additional financing or capital to fund our operations or take advantage of business opportunities that may arise. Further, we may sell additional assets or enter into strategic joint development arrangementsopportunities in order to obtain funding for our operations and capital program if such transactions can be executed on satisfactory terms.
Credit facility
We intend to fund future capital expenditures primarily through cash flows from operations and through borrowings under our revolving credit facility, but we may also issue debt or equity securities, sell additional assets, or enter into joint development arrangements. The issuance of additional debt requires a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
The commitments under our revolving credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating woulddo not trigger a reduction in our current credit facility commitments, nor woulddo such actions trigger a security requirement or change in covenants. The weighted-average interest rate onDowngrades of our credit facility borrowings was 3.19% at December 31, 2017rating will, however, trigger increases in our credit facility's interest rates and we incur commitment fees of 0.30% per annumpaid on the daily average amount of unused borrowing availability.
Our revolving credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. ThisSee Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Long-Term Debt for a discussion of how this ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters ofis calculated pursuant to our credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014.
We were in compliance with our revolving credit facility covenants at December 31, 20172022 and expect to maintain compliance for at least the next 12 months.compliance. At December 31, 2017,2022, our consolidated net debt to total capitalization ratio as defined in our revolving credit facility as amended, was 0.51 to 1.00.0.50. We do not believe the revolving credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing to a material extent if needed to support our business. At December 31, 2017,
Future Capital Requirements
Our material future cash requirements are summarized below. Based on current market indications, we expect to meet our total debt would have neededcontractual cash commitments to independently increase by approximately $5.2 billion above the existing level at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders’ equity would have needed to independently decrease by approximately $2.8 billion (excluding the after-tax impact of any non-cash impairment charges) below the existing level at December 31, 2017 to reach the maximum covenant ratio. These independent point-in-time sensitivities do not take into account other factors that could arise to mitigate the impact of changes in debt and equity on our consolidated net debt to total capitalization ratio, suchthird parties as disposing of assets or exploring alternative sources of capitalization.
Senior notes
Our debt includes outstanding senior note obligations totaling $6.2$6.3 billion at December 31, 2017. We have no near-term senior note maturities, with our earliest scheduled senior note maturity being our $2.0 billion2022, exclusive of 2022 Notes due in September 2022.interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $636 million of 2023 Notes due in April 2023, which is reflected as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022. We expect to be able to generate or obtain sufficient funds necessary to fully redeem our 2023 Notes by the maturity date. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to
We were in compliance with our senior note covenants at December 31, 20172022 and expect to maintain compliance for at least the next 12 months.compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt woulddo not trigger additional senior note covenants.
Credit facility borrowings
As of February 1, 2023, we had $1.14 billion of outstanding borrowings on our credit facility. Our credit facility matures in October 2026.
Term loan
In November 2022, we borrowed $750 million under a three-year term loan agreement, the proceeds of which were used to fund a portion of the Hamm Family's November 2022 take-private transaction. The term loan matures in November 2025 and bears interest at
38
market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness.
The covenant requirements in the term loan are consistent with the covenants in our revolving credit facility, including the requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0. We were in compliance with the term loan covenants at December 31, 2022 and expect to maintain compliance. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger a security requirement or change in covenants for the term loan. Downgrades of our subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC,credit rating will, however, trigger an increase in our term loan's interest rate.
Transportation, gathering, and The Mineral Resources Company, whichprocessing commitments
We have no material assets or operations, fullyentered into transportation, gathering, and unconditionallyprocessing commitments to guarantee the senior notescapacity on a joint and several basis. Our other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes as of December 31, 2017.
Capital Expenditures
2022 Capital Spending
For the year ended December 31, 2017,2022, we invested approximately $2.0$2.70 billion in our capital program excluding $40.0$716.6 million of unbudgeted acquisitions, excluding $12.0 million of mineral acquisitions attributable to Franco-Nevada, and including $79.2$102.1 million of capital costs associated with increased accruals for capital expenditures and including $2.8 million of seismic costs.as compared to December 31, 2021. Our capital expenditures budget for 2017 was $1.95 billion. Our 20172022 capital expenditures were allocated as follows by quarter:
In millions | 1Q 2017 | 2Q 2017 | 3Q 2017 | 4Q 2017 | Total 2017 | ||||||||||
Exploration and development drilling | $ | 329.8 | $ | 471.0 | $ | 444.7 | $ | 442.2 | $ | 1,687.7 | |||||
Land costs | 68.8 | 49.8 | 47.7 | 23.0 | 189.3 | ||||||||||
Capital facilities, workovers and other corporate assets | 27.4 | 29.3 | 28.2 | 30.5 | 115.4 | ||||||||||
Seismic | 1.0 | 1.8 | — | — | 2.8 | ||||||||||
Capital expenditures, excluding acquisitions | $ | 427.0 | $ | 551.9 | $ | 520.6 | $ | 495.7 | $ | 1,995.2 | |||||
Acquisitions of producing properties | 0.1 | 0.7 | 2.7 | 4.9 | 8.4 | ||||||||||
Acquisitions of non-producing properties | 13.3 | 5.1 | 6.8 | 6.4 | 31.6 | ||||||||||
Total acquisitions | 13.4 | 5.8 | 9.5 | 11.3 | 40.0 | ||||||||||
Total capital expenditures | $ | 440.4 | $ | 557.7 | $ | 530.1 | $ | 507.0 | $ | 2,035.2 |
In millions |
| 1Q 2022 |
|
| 2Q 2022 |
|
| 3Q 2022 |
|
| 4Q 2022 |
|
| Total 2022 |
| |||||
Exploration and development drilling |
| $ | 426.2 |
|
| $ | 504.7 |
|
| $ | 686.0 |
|
| $ | 576.6 |
|
| $ | 2,193.5 |
|
Land costs |
|
| 24.3 |
|
|
| 31.2 |
|
|
| 30.6 |
|
|
| 55.5 |
|
|
| 141.6 |
|
Mineral acquisitions attributable to Continental |
|
| 0.5 |
|
|
| 0.4 |
|
|
| 1.0 |
|
|
| 1.0 |
|
|
| 2.9 |
|
Capital facilities, workovers, water infrastructure, and other corporate assets |
|
| 72.3 |
|
|
| 110.9 |
|
|
| 97.4 |
|
|
| 81.2 |
|
|
| 361.8 |
|
Seismic |
|
| 0.6 |
|
|
| 1.3 |
|
|
| 0.9 |
|
|
| 0.4 |
|
|
| 3.2 |
|
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions |
| $ | 523.9 |
|
| $ | 648.5 |
|
| $ | 815.9 |
|
| $ | 714.7 |
|
| $ | 2,703.0 |
|
Unbudgeted acquisitions |
|
| 443.1 |
|
|
| 219.2 |
|
|
| 43.1 |
|
|
| 11.2 |
|
|
| 716.6 |
|
Total capital expenditures attributable to Continental |
| $ | 967.0 |
|
| $ | 867.7 |
|
| $ | 859.0 |
|
| $ | 725.9 |
|
| $ | 3,419.6 |
|
Mineral acquisitions attributable to Franco-Nevada |
|
| 1.9 |
|
|
| 1.8 |
|
|
| 4.2 |
|
|
| 4.1 |
|
|
| 12.0 |
|
Total capital expenditures |
| $ | 968.9 |
|
| $ | 869.5 |
|
| $ | 863.2 |
|
| $ | 730.0 |
|
| $ | 3,431.6 |
|
2023 Capital Expenditures Budget
For 2023, our capital expenditures budget for 2018 is $2.3 billion excluding acquisitions, whichattributable to us is expected to be allocated$3.25 billion. Costs of acquisitions and investments, such as follows:
In millions | Amount | ||
Exploration and development drilling | $ | 1,988 | |
Land costs | 132 | ||
Capital facilities, workovers and other corporate assets | 168 | ||
Seismic | 12 | ||
Total 2018 capital budget, excluding acquisitions | $ | 2,300 |
Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, access to capital, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the availability of transportation, gathering and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale backadjust our spending should commodity prices decreasematerially change from current levels. Conversely, an increase
Strategic Investment
See Note 18. Equity Investment in commodity prices from current levels could result in increased capital expenditures. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at competitive terms.
Payments due by period | ||||||||||||||||||||
In thousands | Total | Less than 1 year (2018) | Years 2 and 3 (2019-2020) | Years 4 and 5 (2021-2022) | More than 5 years | |||||||||||||||
Arising from arrangements on the balance sheet: | ||||||||||||||||||||
Revolving credit facility borrowings | $ | 188,000 | $ | — | $ | 188,000 | $ | — | $ | — | ||||||||||
Senior Notes (1) | 6,200,000 | — | — | 2,000,000 | 4,200,000 | |||||||||||||||
Note payable (2) | 10,021 | 2,286 | 4,795 | 2,940 | — | |||||||||||||||
Interest payments (3) | 2,476,202 | 270,535 | 569,683 | 567,159 | 1,068,825 | |||||||||||||||
Asset retirement obligations (4) | 114,406 | 2,612 | 3,486 | — | 108,308 | |||||||||||||||
Arising from arrangements not on balance sheet: (5) | ||||||||||||||||||||
Operating leases and other (6) | 26,956 | 11,867 | 6,581 | 1,300 | 7,208 | |||||||||||||||
Drilling rig commitments (7) | 103,595 | 72,924 | 30,671 | — | — | |||||||||||||||
Transportation and processing commitments (8) | 1,429,511 | 196,714 | 401,656 | 333,988 | 497,153 | |||||||||||||||
Total contractual obligations | $ | 10,548,691 | $ | 556,938 | $ | 1,204,872 | $ | 2,905,387 | $ | 5,881,494 |
39
Cash Payments for Income Taxes
For the year ended December 31, 2022, we willmade estimated quarterly payments for 2022 U.S. federal income taxes totaling $470 million based on an estimate of federal taxable income for the year. Significant judgment is involved in estimating future taxable income as we are required to make assumptions about future commodity prices, projected production, development activities, capital spending, profitability, and general economic conditions, all of which are subject to material revision in future periods as better information becomes available. If commodity prices remain at current levels, we expect to continue generating significant taxable income through at least year-end 2023, which would result in us continuing to make estimated tax payments on a quarterly basis in 2023 that could approximate the payments made in 2022. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, we cannot predict the amount of future income tax payments with certainty.
Delivery Commitments
We have various natural gas volume delivery commitments that are related to our key operating areas. We expect to primarily fulfill our contractual natural gas obligations with production from our proved reserves. However, we may purchase third-party volumes to satisfy our commitments. Additionally, in the Permian Basin certain of our firm sales contracts for crude oil include delivery commitments that specify the delivery of a fixed and incur costsdeterminable quantity. We expect to primarily fulfill our contractual crude oil obligations with production from our proved reserves. As of December 31, 2022, we were committed to deliver the following fixed quantities of natural gas and crude oil production. The volumes disclosed herein represent gross production associated with the settlementproperties operated by us and do not reflect our net proportionate share of approximately $59.6 million. The timing of payments of our obligations under the settlement is uncertain and have not been reflectedsuch amounts.
Year Ending |
| Natural Gas |
|
| Crude Oil |
| ||
December 31, |
| Bcf |
|
| MMBo |
| ||
2023 |
|
| 167 |
|
|
| 13 |
|
2024 |
|
| 119 |
|
|
| 3 |
|
2025 |
|
| 70 |
|
|
| — |
|
2026 |
|
| 38 |
|
|
| — |
|
2027 |
|
| 4 |
|
|
| — |
|
Derivative Instruments
See Note 6. Derivative Instruments in the contractual obligations table above.
Natural gas derivatives |
|
|
|
|
|
|
|
|
| ||
Period and Type of Contract |
| Average Volumes Hedged |
| Weighted Average Hedge Price ($/MMBtu) |
|
| |||||
April 2023 - December 2023 |
|
|
|
|
|
|
|
|
| ||
Swaps - Henry Hub |
|
| 210,000 |
|
| MMBtus/day |
| $ | 3.89 |
|
|
July 2023 - September 2024 |
|
|
|
|
|
|
|
|
| ||
Swaps - WAHA |
|
| 22,000 |
|
| MMBtus/day |
| $ | 2.64 |
|
|
January 2024 - December 2024 |
|
|
|
|
|
|
|
|
| ||
Swaps - Henry Hub |
|
| 172,400 |
|
| MMBtus/day |
| $ | 3.71 |
|
|
January 2025 - December 2025 |
|
|
|
|
|
|
|
|
| ||
Swaps - Henry Hub |
|
| 180,000 |
|
| MMBtus/day |
| $ | 3.99 |
|
|
January 2026 - December 2026 |
|
|
|
|
|
|
|
|
| ||
Swaps - Henry Hub |
|
| 150,000 |
|
| MMBtus/day |
| $ | 4.03 |
|
|
Crude oil derivatives |
|
|
|
|
|
|
|
| ||
Period and Type of Contract |
| Average Volumes Hedged |
| Weighted Average Hedge Price ($/Bbl) |
| |||||
April 2023 - March 2024 |
|
|
|
|
|
|
|
| ||
Swaps - WTI |
|
| 52,000 |
|
| Bbls/day |
| $ | 77.92 |
|
Senior note repurchases and redemptions
In recent periods we have redeemed or repurchased a portion of our forecasted 2018 natural gas production.outstanding senior notes. From time to time, we may execute additional redemptions or repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. The hedged volumes reflected below represent an aggregationtiming and amount of multiple contracts that are generally expectedany such redemptions or repurchases will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the
40
aggregate, may be material. Our $636 million of 2023 Notes is due in April 2023. We expect to be realized ratably overable to generate or obtain sufficient funds necessary to fully redeem our 2023 Notes by the indicated period. These derivative instruments will be settled based upon reported NYMEX Henry Hub settlement prices.
Swaps Weighted Average Price | |||||||
Period and Type of Contract | MMBtus | ||||||
February 2018 - December 2018 | |||||||
Swaps - Henry Hub | 193,720,000 | $ | 2.88 |
Critical Accounting Policies and Estimates
Our consolidated financial statements and related footnotes contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and the disclosure and estimation of contingent assets and liabilities. See
Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies and Note 9. Revenuesfor descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used.In management’s opinion, the most significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimations, revenue recognition, the choice of accounting method for crude oil and natural gas activities and derivatives, impairment of assets, income taxes and contingent liabilities. These areas are discussed below. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters and are believed to be reasonable under the circumstances. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from the estimates as additional information becomes known.
Crude Oil and Natural Gas Reserves Estimation and Standardized Measure of Future Cash Flows
Our external independent reserve engineers, Ryder Scott, and internal technical staff prepare the estimates of our crude oil and natural gas reserves and associated future net cash flows. Even though Ryder Scott and our internal technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Estimates of reserves and their values, future production rates, and future costs and expenses are inherently uncertain for various reasons, including many factors beyond the Company’s control. Reserve estimates are updated by us at least semi-annually and take into account recent production levels and other technical information about each of our properties.
Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to theor removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered.
Estimates of proved reserves are key components of the Company’s most significant financial estimates including the computation of depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. Future revisions of reserves may be material and could significantly alter future depreciation, depletion, and amortization expense and may result in material impairments of assets.
Our DD&A calculations for oil and gas properties are performed on a field basis and revisions to proved reserves will not necessarily be applied ratably across all fields and may not be applied to some fields at all. Further, reserve revisions in
Revenue Recognition
We derive substantially all of our revenues from the sale of crude oil, and natural gas. Crude oil and natural gas, and NGLs. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues for discussion of our accounting policies governing the recognition and presentation of revenues.
41
Operated crude oil, natural gas, and NGL revenues are recognized induring the month the product is deliveredin which control transfers to the purchasercustomer and title transfers. Weit is probable the Company will collect the consideration it is entitled to receive. For non-operated properties, the Company's proportionate share of production is generally receive payment from onemarketed at the discretion of the operators. Non-operated revenues are recognized by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to three months after the sale has occurred. receive.
At the end of each month, to record revenuerevenues we estimate the amount of production delivered and sold to purchaserscustomers and the prices at which they were sold. Variances between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received and are reflected in our financial statements as crude oil and natural gas sales. These variances have historically not been material.
For the recognitionsale of crude oil, natural gas, and presentation ofNGLs we evaluate whether we are the principal, and report revenues went into effect on January 1, 2018. See
Successful Efforts Method of Accounting
Our business is subject to accounting rules that are unique to the crude oil and natural gas industry. Two generally accepted methods of accounting for oil and gas activities are available
—the successful efforts method and the full cost method. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. We use the successful efforts method of accounting for our oil and gas properties. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies for further discussion of the accounting policies applicable to the successful efforts method of accounting.Derivative Activities
From time to time we utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future crude oil and natural gas production and forecasted purchases of diesel fuel for use in drilling activities.other purposes. We have elected not to designate any of our price risk management activities as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair value in current earnings.
In determining the amounts to be recorded for our openoutstanding derivative contracts, we are required to estimate the fair value of the derivatives. We use an independent third party to provide our derivative valuations. The third party’s valuation models for derivative contracts are industry-standard models that consider various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value calculations for collars requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative agreements and the resulting estimated future cash inflows or outflows over the lives of the derivatives are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates. See
We validate our derivative valuations through management review and by comparison to our counterparties’ valuations for reasonableness. Differences between our fair value calculations and counterparty valuations have historically not been material.
Impairment of Assets
All of our long-lived assets are monitored for potential impairment when circumstances indicate the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk-adjusted proved reserves. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable.
Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis. If the carrying amount of a field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model. For producing properties, the impairment evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce those products, estimates of future crude oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or downward revisions toor removals of crude oil and natural gas reserves. Estimates of anticipated sales prices and recoverable reserves are highly judgmental and are subject to material revision in future periods.
Impairment provisions for producingproved properties totaled $82.3$17.5 million for 2017.the year ended December 31, 2022. Commodity price assumptions used for the year-end December 31, 20172022 impairment calculations were based on publicly available average annual
42
forward commodity strip prices through year-end 20222027 and were then escalated at 3% per year thereafter. Holding all other factors constant, as forward commodity prices decrease, our probability for recognizing producing property impairments may increase, or the magnitude of impairments to be recognized may increase. Conversely, as forward commodity prices increase, our probability for recognizing producing property impairments may decrease, or the magnitude of impairments to be recognized may decrease or be eliminated. As of December 31, 2017,2022, the publicly available forward commodity strip prices for the year 20222027 used in our fourth quarter impairment calculations averaged $51.65$63.87 per barrel for crude oil and $2.89$4.50 per Mcf for natural gas. If forward commodity prices materially decrease from current levels for an extended period, additional impairments of producing properties may be recognized in the future. Because of the uncertainty inherent in the numerous factors utilized in determining the fair value of producing properties, we cannot predict the timing and amount of future impairment charges, if any.
Impairment losses for non-producingunproved properties which primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves, are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. The estimated timing and rate of successful drilling is highly judgmental and is subject to material revision in future periods as better information becomes available.
Income Taxes
Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those differences 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.
In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. We apply judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for our deferred tax assets. In determining whether a valuation allowance is required, we consider, among other factors, our financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and may affect the valuation of deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of the valuation allowance. We believe our deferred tax assets at December 31, 2022 will ultimately be realized. We will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to our deferred tax assets.
We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain deferred tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before theour consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carryforwards.carryforwards, among other things. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood we will be able to recover or utilizeAccordingly, our deferred tax assets. If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2017, we believe all deferred tax assets, net of valuation allowances, reflected in our consolidated balance sheets will ultimately be utilized. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly related to prevailing crude oil and natural gas prices). If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision could increase in the period it is determined that it is more likely than not that a deferred tax asset will not be utilized.
Contingent Liabilities
A provision for legal, environmental and other contingencies is charged to expense when a loss is probable and the loss or range of loss can be reasonably estimated. Determining when liabilities and expenses should be recorded for these contingencies and the appropriate amounts of accruals is subject to an estimation process that requires subjective judgment of management. In certain cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. Actual losses can differ from estimates for various reasons, including differing interpretations of laws and opinions and assessments on the amount of damages. We closely monitor known and potential legal, environmental and other contingencies and make our best estimate of when or if to record liabilities and losses for matters based on available information.
Legislative and Regulatory Developments
The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. President Biden, in pursuit of his regulatory agenda, has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry and there is the potential for the revision of existing laws and regulations or the adoption of new legislation that could adversely affect the oil and gas industry. Such changes, if enacted, could have a material adverse effect on our results of operations and cash flows. See
Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.Inflation Reduction Act
In August 2022, President Biden signed the Tax ReformInflation Reduction Act was signedof 2022 (“IRA”) into law, which represents the most significant tax policy change in the United States since 1986. Below is a summary of key changes included in the new law that are most relevant to our business. Changes arising from the Tax Reform Act, which are subject to a number of important qualifications and exceptions not included in the summary below, generally become effective for tax years beginning after December 31, 2017. The following discussion should be read in conjunction with
We are in the process of evaluating the new law expands the number of individuals whose compensation is subject to the $1 million limitation and expands the types of equity awards to be included in the calculations. These changes will limit our ability to deduct future executive compensation expenses, the impact of which is uncertain but is not expected to be significant to our business.
Inflation
The general rate of inflation has increased in conjunction with overall imbalances in supply and demand recoveries from the reduced corporate tax rate. The new lawsCOVID-19 pandemic. Some of the underlying factors impacting inflation may include, but are not expectedlimited to, adversely impact our liquidity or the amount of cash payments we make for income taxes for at least the next five years.
Non-GAAP Financial Measures
Net crude oil and natural gas sales and net sales prices
Revenues and transportation expenses associated with production from our operated properties are reported separately as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we have presented crude oil, natural gas, and NGL sales net of transportation expenses in Management’s Discussion and Analysis of Financial Condition and Results of Operations, which we refer to as "net crude oil, natural gas, and natural gas liquids sales," a non-GAAP measure. Average sales prices calculated using net sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
44
The following table presents a reconciliation of total Company crude oil, natural gas, and natural gas liquids sales (GAAP) to net crude oil, natural gas, and natural gas liquids sales and related net sales prices (non-GAAP) for 2022, 2021, and 2020.
Total Company |
| Year Ended December 31, 2022 |
|
| Year Ended December 31, 2021 |
|
| Year Ended December 31, 2020 |
| |||||||||||||||||||||||||||
In thousands |
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
|
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
|
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
| |||||||||
Crude oil, natural gas, and NGL sales (GAAP) |
| $ | 6,906,003 |
|
| $ | 3,168,672 |
|
| $ | 10,074,675 |
|
| $ | 3,949,294 |
|
| $ | 1,844,447 |
|
| $ | 5,793,741 |
|
| $ | 2,199,976 |
|
| $ | 355,458 |
|
| $ | 2,555,434 |
|
Less: Transportation expenses |
|
| (253,981 | ) |
|
| (62,433 | ) |
|
| (316,414 | ) |
|
| (185,130 | ) |
|
| (39,859 | ) |
|
| (224,989 | ) |
|
| (158,989 | ) |
|
| (37,703 | ) |
|
| (196,692 | ) |
Net crude oil, natural gas, and NGL sales (non-GAAP) |
| $ | 6,652,022 |
|
| $ | 3,106,239 |
|
| $ | 9,758,261 |
|
| $ | 3,764,164 |
|
| $ | 1,804,588 |
|
| $ | 5,568,752 |
|
| $ | 2,040,987 |
|
| $ | 317,755 |
|
| $ | 2,358,742 |
|
Sales volumes (MBbl/MMcf/MBoe) |
|
| 72,732 |
|
|
| 442,980 |
|
|
| 146,562 |
|
|
| 58,757 |
|
|
| 370,110 |
|
|
| 120,442 |
|
|
| 58,793 |
|
|
| 306,528 |
|
|
| 109,881 |
|
Net sales price (non-GAAP) |
| $ | 91.46 |
|
| $ | 7.01 |
|
| $ | 66.58 |
|
| $ | 64.06 |
|
| $ | 4.88 |
|
| $ | 46.24 |
|
| $ | 34.71 |
|
| $ | 1.04 |
|
| $ | 21.47 |
|
The following tables present reconciliations of crude oil, natural gas, and natural gas liquids sales (GAAP) to net crude oil, natural gas, and natural gas liquids sales and related net sales prices (non-GAAP) for North Dakota Bakken, SCOOP, and the Permian Basin for 2022, 2021, and 2020 as presented in Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Production and Price History.
North Dakota Bakken |
| Year Ended December 31, 2022 |
|
| Year Ended December 31, 2021 |
|
| Year Ended December 31, 2020 |
| |||||||||||||||||||||||||||
In thousands |
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
|
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
|
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
| |||||||||
Crude oil, natural gas, and NGL sales (GAAP) |
| $ | 3,768,200 |
|
| $ | 1,033,098 |
|
| $ | 4,801,298 |
|
| $ | 2,695,738 |
|
| $ | 549,932 |
|
| $ | 3,245,670 |
|
| $ | 1,469,450 |
|
| $ | 24,714 |
|
| $ | 1,494,164 |
|
Less: Transportation expenses |
|
| (183,471 | ) |
|
| (15,573 | ) |
|
| (199,044 | ) |
|
| (154,359 | ) |
|
| (4,831 | ) |
|
| (159,190 | ) |
|
| (127,036 | ) |
|
| (2,580 | ) |
|
| (129,616 | ) |
Net crude oil, natural gas, and NGL sales (non-GAAP) |
| $ | 3,584,729 |
|
| $ | 1,017,525 |
|
| $ | 4,602,254 |
|
| $ | 2,541,379 |
|
| $ | 545,101 |
|
| $ | 3,086,480 |
|
| $ | 1,342,414 |
|
| $ | 22,134 |
|
| $ | 1,364,548 |
|
Sales volumes (MBbl/MMcf/MBoe) |
|
| 39,871 |
|
|
| 124,411 |
|
|
| 60,606 |
|
|
| 40,186 |
|
|
| 120,517 |
|
|
| 60,272 |
|
|
| 40,040 |
|
|
| 97,532 |
|
|
| 56,295 |
|
Net sales price (non-GAAP) |
| $ | 89.91 |
|
| $ | 8.18 |
|
| $ | 75.94 |
|
| $ | 63.24 |
|
| $ | 4.52 |
|
| $ | 51.21 |
|
| $ | 33.53 |
|
| $ | 0.23 |
|
| $ | 24.24 |
|
SCOOP |
| Year Ended December 31, 2022 |
|
| Year Ended December 31, 2021 |
|
| Year Ended December 31, 2020 |
| |||||||||||||||||||||||||||
In thousands |
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
|
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
|
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
| |||||||||
Crude oil, natural gas, and NGL sales (GAAP) |
| $ | 951,754 |
|
| $ | 1,300,731 |
|
| $ | 2,252,485 |
|
| $ | 756,596 |
|
| $ | 980,323 |
|
| $ | 1,736,919 |
|
| $ | 486,076 |
|
| $ | 246,125 |
|
| $ | 732,201 |
|
Less: Transportation expenses |
|
| (3,027 | ) |
|
| (23,915 | ) |
|
| (26,942 | ) |
|
| (2,854 | ) |
|
| (23,808 | ) |
|
| (26,662 | ) |
|
| (5,275 | ) |
|
| (21,909 | ) |
|
| (27,184 | ) |
Net crude oil, natural gas, and NGL sales (non-GAAP) |
| $ | 948,727 |
|
| $ | 1,276,816 |
|
| $ | 2,225,543 |
|
| $ | 753,742 |
|
| $ | 956,515 |
|
| $ | 1,710,257 |
|
| $ | 480,801 |
|
| $ | 224,216 |
|
| $ | 705,017 |
|
Sales volumes (MBbl/MMcf/MBoe) |
|
| 10,063 |
|
|
| 185,755 |
|
|
| 41,022 |
|
|
| 11,341 |
|
|
| 179,553 |
|
|
| 41,267 |
|
|
| 12,694 |
|
|
| 136,410 |
|
|
| 35,429 |
|
Net sales price (non-GAAP) |
| $ | 94.28 |
|
| $ | 6.87 |
|
| $ | 54.25 |
|
| $ | 66.46 |
|
| $ | 5.33 |
|
| $ | 41.44 |
|
| $ | 37.88 |
|
| $ | 1.64 |
|
| $ | 19.90 |
|
Permian Basin |
| Year Ended December 31, 2022 |
| |||||||||
In thousands |
| Crude oil |
|
| Natural gas and NGLs |
|
| Total |
| |||
Crude oil, natural gas, and NGL sales (GAAP) |
| $ | 1,122,290 |
|
| $ | 151,217 |
|
| $ | 1,273,507 |
|
Less: Transportation expenses |
|
| (28,499 | ) |
|
| (6,594 | ) |
|
| (35,093 | ) |
Net crude oil, natural gas, and NGL sales (non-GAAP) |
| $ | 1,093,791 |
|
| $ | 144,623 |
|
| $ | 1,238,414 |
|
Sales volumes (MBbl/MMcf/MBoe) |
|
| 11,796 |
|
|
| 20,804 |
|
|
| 15,264 |
|
Net sales price (non-GAAP) |
| $ | 92.73 |
|
| $ | 6.95 |
|
| $ | 81.13 |
|
PV-10
Our PV-10 value, a non-GAAP financial measure, is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31, 2017,2022, our PV-10 totaled approximately $11.83$39.96 billion. The standardized measure of our discounted future net cash flows was approximately $10.47$31.91 billion at December 31, 2017,2022, representing a $1.36an $8.05 billion difference from PV-10 due to the effect of deducting estimated future income taxes in arriving at Standardized Measure. We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties.
45
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
General.
We are exposed to a variety of market risks including commodity price risk, credit risk, and interest rate risk. We seek to address these risks through a program of risk management which may include the use of derivative instruments.Commodity Price Risk.
Our primary market risk exposure is in the prices we receive from sales of our crude oil, natural gas, and natural gasTo reduce price risk caused by market fluctuations in crude oil and natural gascommodity prices, from time to time we may economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program.program and for general corporate purposes. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to liquidatesettle existing derivative positions prior to the expiration of their contractual maturities in order to monetize gain positions for the purpose of funding our capital program.maturities. While hedging, if utilized, limitsmay limit the downside risk of adverse price movements, it also limitsmay limit future revenues from upward price movements. We have hedged the majority
The fair value of our forecasted 2018derivative instruments at December 31, 2022 was a net liability of $178.7 million, which is comprised of a $193.2 million net liability associated with our natural gas production. Our futurederivatives partially offset by a $14.5 million net asset associated with our crude oil production is currently unhedged and directly exposedderivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to continued volatility in market prices, whether favorable or unfavorable.
|
|
|
| Hypothetical Fair Value |
| |
In thousands |
| Change in Forward Price |
| Asset (Liability) |
| |
Crude Oil |
| -10% |
| $ | 37,210 |
|
Crude Oil |
| +10% |
| $ | (8,146 | ) |
Natural Gas |
| -10% |
| $ | (63,363 | ) |
Natural Gas |
| +10% |
| $ | (323,396 | ) |
Changes in the fair value of our natural gas derivatives from the above price sensitivities would produce a corresponding change in our total revenues.
Credit Risk.
We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.
Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $35$16 million at December 31, 2017,2022, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner’s interest in the well, to redirectnet production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.
Interest Rate Risk
. Our exposure to changes in interest rates relates46
of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.
We had $1.14 billion of variable rate borrowings outstanding on our credit facility and $750 million of variable rate borrowings on our term loan at February 1, 2023. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $4.7 million per year.
We manage our interest rate exposure by monitoring both the effects of market changes in interest rates and the proportion of our debt portfolio that is variable-rate versus fixed-rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We currently have no interest rate derivatives.
The following table presents our debt maturities and the weighted average interest rates by expected maturity date as of December 31, 2017:
In thousands |
| 2023 |
|
| 2024 |
|
| 2025 |
|
| 2026 |
|
| 2027 |
|
| Thereafter |
|
| Total |
| |||||||
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Principal amount (1) |
| $ | 636,000 |
|
| $ | 893,126 |
|
| $ | — |
|
| $ | 800,000 |
|
| $ | — |
|
| $ | 4,000,000 |
|
| $ | 6,329,126 |
|
Weighted-average interest rate |
|
| 4.5 | % |
|
| 3.8 | % |
|
| — |
|
|
| 2.3 | % |
|
| — |
|
|
| 4.7 | % |
|
| 4.2 | % |
Notes payable: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Principal amount (1) |
| $ | 2,410 |
|
| $ | 2,495 |
|
| $ | 2,587 |
|
| $ | 2,681 |
|
| $ | 2,777 |
|
| $ | 7,175 |
|
| $ | 20,125 |
|
Interest rate |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Credit facility: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Principal amount |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 1,160,000 |
|
| $ | — |
|
| $ | — |
|
| $ | 1,160,000 |
|
Weighted-average interest rate |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5.9 | % |
|
| — |
|
|
| — |
|
|
| 5.9 | % |
Term loan: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Principal amount |
| $ | — |
|
| $ | — |
|
| $ | 750,000 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 750,000 |
|
Interest rate |
|
| — |
|
|
| — |
|
|
| 6.1 | % |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 6.1 | % |
In thousands | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | |||||||||||||||||||||
Fixed rate debt: | ||||||||||||||||||||||||||||
Senior Notes: | ||||||||||||||||||||||||||||
Principal amount (1) | $ | — | $ | — | $ | — | $ | — | $ | 2,000,000 | $ | 4,200,000 | $ | 6,200,000 | ||||||||||||||
Weighted-average interest rate | — | — | — | — | 5.0 | % | 4.4 | % | 4.6 | % | ||||||||||||||||||
Note payable: | ||||||||||||||||||||||||||||
Principal amount | $ | 2,286 | $ | 2,360 | $ | 2,435 | $ | 2,515 | $ | 425 | $ | — | $ | 10,021 | ||||||||||||||
Interest rate | 3.1 | % | 3.1 | % | 3.1 | % | 3.1 | % | 3.1 | % | — | 3.1 | % | |||||||||||||||
Variable rate debt: | ||||||||||||||||||||||||||||
Revolving credit facility: | ||||||||||||||||||||||||||||
Principal amount | $ | — | $ | 188,000 | $ | — | $ | — | $ | — | $ | — | $ | 188,000 | ||||||||||||||
Weighted-average interest rate | — | 3.2 | % | — | — | — | — | 3.2 | % |
47
Item 8. Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
(PCAOB ID Number 248) | 49 | |
51 | ||
52 | ||
53 | ||
54 | ||
55 |
48
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Continental Resources, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries (the “Company”) as of December 31, 20172022 and 2016,2021, the related consolidated statements of comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172022 and 2016,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2022, in conformity with accounting principles generally accepted in the United States of America.
Basis for opinion
These financial statements are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOBPublic Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB.PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense, proved and unproved crude oil and natural gas reserves used in the assessment and measurement of impairment, and the valuation of crude oil and natural gas properties in the 2022 Powder River Basin Acquisition (herein referred to as "the crude oil and natural gas reserves")
As described in Note 1 to the consolidated financial statements, the Company accounts for its crude oil and natural gas properties using the successful efforts method of accounting, which requires management to make estimates of proved crude oil and natural gas reserve volumes and future cash flows to record depletion expense and proved and unproved crude oil and natural gas reserves to assess its crude oil and natural gas properties for impairment. Additionally, as described in Note 2 to the consolidated financial statements, the Company acquired significant oil and natural gas properties through asset acquisitions. Crude oil and natural gas reserves are a significant input to the determination of the acquisition date fair value of crude oil and natural gas properties acquired by the Company in asset acquisitions. To estimate the crude oil and natural gas reserves and future cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of producing crude oil and natural gas properties and forecasting the timing and volume of production associated with the Company's development plan for proved undeveloped properties and unproved properties. In addition, the estimation of the crude oil and natural gas reserves is also impacted by management's judgments and estimates regarding the financial performance of wells associated with the crude oil and natural gas reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and impairment assessments/measurements. We identified the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and the recording of fair values of properties
49
acquired in the 2022 Powder River Basin Acquisition, and proved and unproved crude oil and natural gas reserves for the assessment/measurement of impairment of crude oil and natural gas properties as a critical audit matter.
The principal consideration for our determination that the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment of crude oil and natural gas properties and the recording of oil and natural gas property values in the 2022 Powder River Basin Acquisition is a critical audit matter is that relatively minor changes in certain highly subjective inputs and assumptions that are necessary to estimate the volume and future cash flows of the Company's crude oil and natural gas reserves could have a significant impact on the measurement of depletion expense or assessment / measurement of impairment expense and the acquisition date values of crude oil and natural gas properties.
Our audit procedures related to the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment and measurement of impairment and the amount of crude oil and natural gas properties recorded from acquisitions included the following, among others:
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2004.
Oklahoma City, Oklahoma
February 21, 2018
50
Continental Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
December 31, | ||||||||
In thousands, except par values and share data | 2017 | 2016 | ||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 43,902 | $ | 16,643 | ||||
Receivables: | ||||||||
Crude oil and natural gas sales | 671,665 | 404,750 | ||||||
Affiliated parties | 63 | 99 | ||||||
Joint interest and other, net | 426,585 | 364,850 | ||||||
Derivative assets | 2,603 | 4,061 | ||||||
Inventories | 97,406 | 111,987 | ||||||
Prepaid expenses and other | 9,501 | 10,843 | ||||||
Total current assets | 1,251,725 | 913,233 | ||||||
Net property and equipment, based on successful efforts method of accounting | 12,933,789 | 12,881,227 | ||||||
Other noncurrent assets | 14,137 | 17,316 | ||||||
Total assets | $ | 14,199,651 | $ | 13,811,776 | ||||
Liabilities and shareholders’ equity | ||||||||
Current liabilities: | ||||||||
Accounts payable trade | $ | 692,908 | $ | 476,342 | ||||
Revenues and royalties payable | 374,831 | 217,425 | ||||||
Payables to affiliated parties | 143 | 148 | ||||||
Accrued liabilities and other | 260,074 | 176,770 | ||||||
Derivative liabilities | — | 59,489 | ||||||
Current portion of long-term debt | 2,286 | 2,219 | ||||||
Total current liabilities | 1,330,242 | 932,393 | ||||||
Long-term debt, net of current portion | 6,351,405 | 6,577,697 | ||||||
Other noncurrent liabilities: | ||||||||
Deferred income tax liabilities, net | 1,259,558 | 1,890,305 | ||||||
Asset retirement obligations, net of current portion | 111,794 | 94,436 | ||||||
Other noncurrent liabilities | 15,449 | 14,949 | ||||||
Total other noncurrent liabilities | 1,386,801 | 1,999,690 | ||||||
Commitments and contingencies (Note 10) | ||||||||
Shareholders’ equity: | ||||||||
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding | — | — | ||||||
Common stock, $0.01 par value; 1,000,000,000 shares authorized; | ||||||||
375,219,769 shares issued and outstanding at December 31, 2017; | ||||||||
374,492,357 shares issued and outstanding at December 31, 2016 | 3,752 | 3,745 | ||||||
Additional paid-in capital | 1,409,326 | 1,375,290 | ||||||
Accumulated other comprehensive income (loss) | 307 | (260 | ) | |||||
Retained earnings | 3,717,818 | 2,923,221 | ||||||
Total shareholders’ equity | 5,131,203 | 4,301,996 | ||||||
Total liabilities and shareholders’ equity | $ | 14,199,651 | $ | 13,811,776 |
|
| December 31, |
| |||||
In thousands, except par values and share data |
| 2022 |
|
| 2021 |
| ||
Assets |
|
|
|
|
|
| ||
Current assets: |
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 137,788 |
|
| $ | 20,868 |
|
Receivables: |
|
|
|
|
|
| ||
Crude oil, natural gas, and natural gas liquids sales |
|
| 1,313,538 |
|
|
| 1,122,415 |
|
Joint interest and other |
|
| 458,391 |
|
|
| 278,753 |
|
Allowance for credit losses |
|
| (5,514 | ) |
|
| (2,814 | ) |
Receivables, net |
|
| 1,766,415 |
|
|
| 1,398,354 |
|
Derivative assets |
|
| 39,280 |
|
|
| 22,334 |
|
Inventories |
|
| 173,264 |
|
|
| 105,568 |
|
Prepaid expenses and other |
|
| 27,508 |
|
|
| 17,266 |
|
Total current assets |
|
| 2,144,255 |
|
|
| 1,564,390 |
|
Net property and equipment, based on successful efforts method of accounting |
|
| 18,471,914 |
|
|
| 16,975,465 |
|
Investment in unconsolidated affiliates |
|
| 210,805 |
|
|
| — |
|
Operating lease right-of-use assets |
|
| 25,158 |
|
|
| 16,370 |
|
Derivative assets, noncurrent |
|
| 3,548 |
|
|
| 13,188 |
|
Other noncurrent assets |
|
| 22,670 |
|
|
| 21,698 |
|
Total assets |
| $ | 20,878,350 |
|
| $ | 18,591,111 |
|
Liabilities and equity |
|
|
|
|
|
| ||
Current liabilities: |
|
|
|
|
|
| ||
Accounts payable trade |
| $ | 850,547 |
|
| $ | 582,317 |
|
Revenues and royalties payable |
|
| 882,256 |
|
|
| 627,171 |
|
Accrued liabilities and other |
|
| 343,777 |
|
|
| 285,740 |
|
Current portion of incentive compensation liability |
|
| 125,653 |
|
|
| — |
|
Current portion of income tax liabilities |
|
| 152,149 |
|
|
| — |
|
Derivative liabilities |
|
| 88,136 |
|
|
| 899 |
|
Current portion of operating lease liabilities |
|
| 4,086 |
|
|
| 1,674 |
|
Current portion of long-term debt |
|
| 638,058 |
|
|
| 2,326 |
|
Total current liabilities |
|
| 3,084,662 |
|
|
| 1,500,127 |
|
Long-term debt, net of current portion |
|
| 7,571,582 |
|
|
| 6,826,566 |
|
Other noncurrent liabilities: |
|
|
|
|
|
| ||
Deferred income tax liabilities, net |
|
| 2,538,312 |
|
|
| 2,139,884 |
|
Incentive compensation liability, net of current portion |
|
| 100,066 |
|
|
| — |
|
Asset retirement obligations, net of current portion |
|
| 257,152 |
|
|
| 215,701 |
|
Derivative liabilities, noncurrent |
|
| 133,363 |
|
|
| 318 |
|
Operating lease liabilities, net of current portion |
|
| 20,055 |
|
|
| 13,800 |
|
Other noncurrent liabilities |
|
| 43,550 |
|
|
| 38,390 |
|
Total other noncurrent liabilities |
|
| 3,092,498 |
|
|
| 2,408,093 |
|
Commitments and contingencies (Note 13) |
|
|
|
|
|
| ||
Equity: |
|
|
|
|
|
| ||
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding |
|
| — |
|
|
| — |
|
Common stock, $0.01 par value; 1,000,000,000 shares authorized; |
|
|
|
|
|
| ||
299,610,267 shares issued and outstanding at December 31, 2022; |
|
|
|
|
|
| ||
364,297,520 shares issued and outstanding at December 31, 2021; |
|
| 2,996 |
|
|
| 3,643 |
|
Additional paid-in capital |
|
| — |
|
|
| 1,131,602 |
|
Retained earnings |
|
| 6,754,174 |
|
|
| 6,340,211 |
|
Total shareholders’ equity attributable to Continental Resources |
|
| 6,757,170 |
|
|
| 7,475,456 |
|
Noncontrolling interests |
|
| 372,438 |
|
|
| 380,869 |
|
Total equity |
|
| 7,129,608 |
|
|
| 7,856,325 |
|
Total liabilities and equity |
| $ | 20,878,350 |
|
| $ | 18,591,111 |
|
The accompanying notes are an integral part of these consolidated financial statements.
51
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income (Loss)
Year Ended December 31, | ||||||||||||
In thousands, except per share data | 2017 | 2016 | 2015 | |||||||||
Revenues: | ||||||||||||
Crude oil and natural gas sales | $ | 2,982,966 | $ | 2,026,958 | $ | 2,551,131 | ||||||
Crude oil and natural gas sales to affiliates | — | — | 1,400 | |||||||||
Gain (loss) on crude oil and natural gas derivatives, net | 91,647 | (71,859 | ) | 91,085 | ||||||||
Crude oil and natural gas service operations | 46,215 | 25,174 | 36,551 | |||||||||
Total revenues | 3,120,828 | 1,980,273 | 2,680,167 | |||||||||
Operating costs and expenses: | ||||||||||||
Production expenses | 324,214 | 289,289 | 347,243 | |||||||||
Production expenses to affiliates | — | — | 1,654 | |||||||||
Production taxes | 208,278 | 142,388 | 200,637 | |||||||||
Exploration expenses | 12,393 | 16,972 | 19,413 | |||||||||
Crude oil and natural gas service operations | 16,880 | 11,386 | 17,337 | |||||||||
Depreciation, depletion, amortization and accretion | 1,674,901 | 1,708,744 | 1,749,056 | |||||||||
Property impairments | 237,370 | 237,292 | 402,131 | |||||||||
General and administrative expenses | 191,706 | 169,580 | 189,846 | |||||||||
Litigation settlement | 59,600 | — | — | |||||||||
Net gain on sale of assets and other | (53,915 | ) | (307,844 | ) | (23,149 | ) | ||||||
Total operating costs and expenses | 2,671,427 | 2,267,807 | 2,904,168 | |||||||||
Income (loss) from operations | 449,401 | (287,534 | ) | (224,001 | ) | |||||||
Other income (expense): | ||||||||||||
Interest expense | (294,495 | ) | (320,562 | ) | (313,079 | ) | ||||||
Loss on extinguishment of debt | (554 | ) | (26,055 | ) | — | |||||||
Other | 1,715 | 1,697 | 1,995 | |||||||||
(293,334 | ) | (344,920 | ) | (311,084 | ) | |||||||
Income (loss) before income taxes | 156,067 | (632,454 | ) | (535,085 | ) | |||||||
Benefit for income taxes | 633,380 | 232,775 | 181,417 | |||||||||
Net income (loss) | $ | 789,447 | $ | (399,679 | ) | $ | (353,668 | ) | ||||
Basic net income (loss) per share | $ | 2.13 | $ | (1.08 | ) | $ | (0.96 | ) | ||||
Diluted net income (loss) per share | $ | 2.11 | $ | (1.08 | ) | $ | (0.96 | ) | ||||
Comprehensive income (loss): | ||||||||||||
Net income (loss) | $ | 789,447 | $ | (399,679 | ) | $ | (353,668 | ) | ||||
Other comprehensive income (loss), net of tax: | ||||||||||||
Foreign currency translation adjustments | 567 | 3,094 | (2,969 | ) | ||||||||
Total other comprehensive income (loss), net of tax | 567 | 3,094 | (2,969 | ) | ||||||||
Comprehensive income (loss) | $ | 790,014 | $ | (396,585 | ) | $ | (356,637 | ) |
|
| Year Ended December 31, |
| |||||||||
In thousands, except per share data |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Revenues: |
|
|
|
|
|
|
|
|
| |||
Crude oil, natural gas, and natural gas liquids sales |
| $ | 10,074,675 |
|
| $ | 5,793,741 |
|
| $ | 2,555,434 |
|
Loss on derivative instruments, net |
|
| (671,095 | ) |
|
| (128,864 | ) |
|
| (14,658 | ) |
Crude oil and natural gas service operations |
|
| 70,128 |
|
|
| 54,441 |
|
|
| 45,694 |
|
Total revenues |
|
| 9,473,708 |
|
|
| 5,719,318 |
|
|
| 2,586,470 |
|
|
|
|
|
|
|
|
|
|
| |||
Operating costs and expenses: |
|
|
|
|
|
|
|
|
| |||
Production expenses |
|
| 621,921 |
|
|
| 406,906 |
|
|
| 359,267 |
|
Production and ad valorem taxes |
|
| 730,132 |
|
|
| 404,362 |
|
|
| 192,718 |
|
Transportation, gathering, processing, and compression |
|
| 316,414 |
|
|
| 224,989 |
|
|
| 196,692 |
|
Exploration expenses |
|
| 23,068 |
|
|
| 21,047 |
|
|
| 17,732 |
|
Crude oil and natural gas service operations |
|
| 37,002 |
|
|
| 21,480 |
|
|
| 18,294 |
|
Depreciation, depletion, amortization and accretion |
|
| 1,885,465 |
|
|
| 1,898,082 |
|
|
| 1,880,959 |
|
Property impairments |
|
| 70,417 |
|
|
| 38,370 |
|
|
| 277,941 |
|
Transaction costs |
|
| 33,796 |
|
|
| 13,920 |
|
|
| — |
|
General and administrative expenses |
|
| 401,551 |
|
|
| 233,628 |
|
|
| 196,572 |
|
Net (gain) loss on sale of assets and other |
|
| 262 |
|
|
| (5,146 | ) |
|
| 187 |
|
Total operating costs and expenses |
|
| 4,120,028 |
|
|
| 3,257,638 |
|
|
| 3,140,362 |
|
Income (loss) from operations |
|
| 5,353,680 |
|
|
| 2,461,680 |
|
|
| (553,892 | ) |
Other income (expense): |
|
|
|
|
|
|
|
|
| |||
Interest expense |
|
| (300,662 | ) |
|
| (251,598 | ) |
|
| (258,240 | ) |
Gain (loss) on extinguishment of debt |
|
| (403 | ) |
|
| (290 | ) |
|
| 35,719 |
|
Other |
|
| 15,798 |
|
|
| (23,654 | ) |
|
| 1,662 |
|
|
|
| (285,267 | ) |
|
| (275,542 | ) |
|
| (220,859 | ) |
Income (loss) before income taxes |
|
| 5,068,413 |
|
|
| 2,186,138 |
|
|
| (774,751 | ) |
(Provision) benefit for income taxes |
|
| (1,020,804 | ) |
|
| (519,730 | ) |
|
| 169,190 |
|
Income (loss) before equity in net loss of affiliate |
|
| 4,047,609 |
|
|
| 1,666,408 |
|
|
| (605,561 | ) |
Equity in net loss of affiliate |
|
| (1,489 | ) |
|
| — |
|
|
| — |
|
Net income (loss) |
|
| 4,046,120 |
|
|
| 1,666,408 |
|
|
| (605,561 | ) |
Net income (loss) attributable to noncontrolling interests |
|
| 21,562 |
|
|
| 5,440 |
|
|
| (8,692 | ) |
Net income (loss) attributable to Continental Resources |
| $ | 4,024,558 |
|
| $ | 1,660,968 |
|
| $ | (596,869 | ) |
|
|
|
|
|
|
|
|
|
| |||
Net income (loss) per share attributable to Continental Resources: |
|
|
|
|
|
|
|
|
| |||
Basic |
| $ | 11.45 |
|
| $ | 4.61 |
|
| $ | (1.65 | ) |
Diluted |
| $ | 11.45 |
|
| $ | 4.56 |
|
| $ | (1.65 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
52
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Shareholders’ Equity
In thousands, except share data | Shares outstanding | Common stock | Additional paid-in capital | Accumulated other comprehensive income (loss) | Retained earnings | Total shareholders’ equity | |||||||||||||||||
Balance at December 31, 2014 | 372,005,502 | $ | 3,720 | $ | 1,287,941 | $ | (385 | ) | $ | 3,676,568 | $ | 4,967,844 | |||||||||||
Net loss | — | — | — | — | (353,668 | ) | (353,668 | ) | |||||||||||||||
Other comprehensive loss, net of tax | — | — | — | (2,969 | ) | — | (2,969 | ) | |||||||||||||||
Stock-based compensation | — | — | 51,817 | — | — | 51,817 | |||||||||||||||||
Tax benefit from stock-based compensation | — | — | 13,177 | — | — | 13,177 | |||||||||||||||||
Restricted stock: | |||||||||||||||||||||||
Granted | 1,462,534 | 15 | — | — | — | 15 | |||||||||||||||||
Repurchased and canceled | (172,786 | ) | (2 | ) | (7,311 | ) | — | — | (7,313 | ) | |||||||||||||
Forfeited | (336,170 | ) | (3 | ) | — | — | — | (3 | ) | ||||||||||||||
Balance at December 31, 2015 | 372,959,080 | $ | 3,730 | $ | 1,345,624 | $ | (3,354 | ) | $ | 3,322,900 | $ | 4,668,900 | |||||||||||
Net loss | — | — | — | — | (399,679 | ) | (399,679 | ) | |||||||||||||||
Other comprehensive income, net of tax | — | — | — | 3,094 | — | 3,094 | |||||||||||||||||
Stock-based compensation | — | — | 48,084 | — | — | 48,084 | |||||||||||||||||
Tax deficiency from stock-based compensation | — | — | (9,828 | ) | — | — | (9,828 | ) | |||||||||||||||
Restricted stock: | |||||||||||||||||||||||
Granted | 2,064,508 | 20 | — | — | — | 20 | |||||||||||||||||
Repurchased and canceled | (337,981 | ) | (3 | ) | (8,590 | ) | — | — | (8,593 | ) | |||||||||||||
Forfeited | (193,250 | ) | (2 | ) | — | — | — | (2 | ) | ||||||||||||||
Balance at December 31, 2016 | 374,492,357 | $ | 3,745 | $ | 1,375,290 | $ | (260 | ) | $ | 2,923,221 | $ | 4,301,996 | |||||||||||
Cumulative effect adjustment from adoption of ASU 2016-09 (see Note 1) | — | — | — | — | 5,150 | 5,150 | |||||||||||||||||
Net income | — | — | — | — | 789,447 | 789,447 | |||||||||||||||||
Other comprehensive income, net of tax | — | — | — | 567 | — | 567 | |||||||||||||||||
Stock-based compensation | — | — | 45,854 | — | — | 45,854 | |||||||||||||||||
Restricted stock: | |||||||||||||||||||||||
Granted | 1,585,870 | 16 | — | — | — | 16 | |||||||||||||||||
Repurchased and canceled | (259,729 | ) | (3 | ) | (11,818 | ) | — | — | (11,821 | ) | |||||||||||||
Forfeited | (598,729 | ) | (6 | ) | — | — | — | (6 | ) | ||||||||||||||
Balance at December 31, 2017 | 375,219,769 | $ | 3,752 | $ | 1,409,326 | $ | 307 | $ | 3,717,818 | $ | 5,131,203 |
|
| Shareholders’ equity attributable to Continental Resources |
|
|
|
|
|
|
| |||||||||||||||||||||||
In thousands, except share data |
| Shares |
|
| Common |
|
| Additional |
|
| Treasury |
|
| Retained |
|
| Total shareholders’ equity of Continental Resources |
|
| Noncontrolling |
|
| Total |
| ||||||||
Balance at December 31, 2019 |
|
| 371,074,036 |
|
| $ | 3,711 |
|
| $ | 1,274,732 |
|
| $ | — |
|
| $ | 5,463,224 |
|
| $ | 6,741,667 |
|
| $ | 366,684 |
|
| $ | 7,108,351 |
|
Net loss |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (596,869 | ) |
|
| (596,869 | ) |
|
| (8,692 | ) |
|
| (605,561 | ) |
Cumulative effect adjustment from adoption of ASU 2016-13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (137 | ) |
|
| (137 | ) |
|
|
|
|
| (137 | ) | |||||
Cash dividends declared |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (18,580 | ) |
|
| (18,580 | ) |
|
| — |
|
|
| (18,580 | ) |
Change in dividends payable |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 8 |
|
|
| 8 |
|
|
| — |
|
|
| 8 |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (126,906 | ) |
|
| — |
|
|
| (126,906 | ) |
|
| — |
|
|
| (126,906 | ) |
Common stock retired |
|
| (8,122,104 | ) |
|
| (81 | ) |
|
| (126,825 | ) |
|
| 126,906 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
|
| — |
|
|
| — |
|
|
| 64,585 |
|
|
| — |
|
|
| — |
|
|
| 64,585 |
|
|
| — |
|
|
| 64,585 |
|
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Granted |
|
| 2,738,625 |
|
|
| 27 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 27 |
|
|
| — |
|
|
| 27 |
|
Repurchased and canceled |
|
| (306,845 | ) |
|
| (3 | ) |
|
| (7,344 | ) |
|
| — |
|
|
| — |
|
|
| (7,347 | ) |
|
| — |
|
|
| (7,347 | ) |
Forfeited |
|
| (163,277 | ) |
|
| (2 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2 | ) |
|
| — |
|
|
| (2 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 21,557 |
|
|
| 21,557 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (13,270 | ) |
|
| (13,270 | ) |
Balance at December 31, 2020 |
|
| 365,220,435 |
|
| $ | 3,652 |
|
| $ | 1,205,148 |
|
| $ | — |
|
| $ | 4,847,646 |
|
| $ | 6,056,446 |
|
| $ | 366,279 |
|
| $ | 6,422,725 |
|
Net income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,660,968 |
|
|
| 1,660,968 |
|
|
| 5,440 |
|
|
| 1,666,408 |
|
Cash dividends declared |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (168,536 | ) |
|
| (168,536 | ) |
|
| — |
|
|
| (168,536 | ) |
Change in dividends payable |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 133 |
|
|
| 133 |
|
|
| — |
|
|
| 133 |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (123,924 | ) |
|
| — |
|
|
| (123,924 | ) |
|
| — |
|
|
| (123,924 | ) |
Common stock retired |
|
| (3,198,571 | ) |
|
| (32 | ) |
|
| (123,892 | ) |
|
| 123,924 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
|
| — |
|
|
| — |
|
|
| 63,145 |
|
|
| — |
|
|
| — |
|
|
| 63,145 |
|
|
| — |
|
|
| 63,145 |
|
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Granted |
|
| 3,050,491 |
|
|
| 31 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 31 |
|
|
| — |
|
|
| 31 |
|
Repurchased and canceled |
|
| (478,697 | ) |
|
| (5 | ) |
|
| (12,799 | ) |
|
| — |
|
|
|
|
|
| (12,804 | ) |
|
| — |
|
|
| (12,804 | ) | |
Forfeited |
|
| (296,138 | ) |
|
| (3 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (3 | ) |
|
| — |
|
|
| (3 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 33,086 |
|
|
| 33,086 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (23,936 | ) |
|
| (23,936 | ) |
Balance at December 31, 2021 |
|
| 364,297,520 |
|
| $ | 3,643 |
|
| $ | 1,131,602 |
|
| $ | — |
|
| $ | 6,340,211 |
|
| $ | 7,475,456 |
|
| $ | 380,869 |
|
| $ | 7,856,325 |
|
Net income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 4,024,558 |
|
|
| 4,024,558 |
|
|
| 21,562 |
|
|
| 4,046,120 |
|
Cash dividends declared |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (287,035 | ) |
|
| (287,035 | ) |
|
| — |
|
|
| (287,035 | ) |
Change in dividends payable |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 205 |
|
|
| 205 |
|
|
| — |
|
|
| 205 |
|
Common stock repurchased prior to take-private transaction |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (99,855 | ) |
|
| — |
|
|
| (99,855 | ) |
|
| — |
|
|
| (99,855 | ) |
Common stock retired prior to take-private transaction |
|
| (1,842,422 | ) |
|
| (18 | ) |
|
| (99,837 | ) |
|
| 99,855 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
|
| — |
|
|
| — |
|
|
| (8,085 | ) |
|
| — |
|
|
| — |
|
|
| (8,085 | ) |
|
| — |
|
|
| (8,085 | ) |
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Granted |
|
| 1,575,847 |
|
|
| 16 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 16 |
|
|
| — |
|
|
| 16 |
|
Repurchased and canceled |
|
| (627,742 | ) |
|
| (7 | ) |
|
| (35,438 | ) |
|
| — |
|
|
|
|
|
| (35,445 | ) |
|
| — |
|
|
| (35,445 | ) | |
Forfeited |
|
| (384,536 | ) |
|
| (4 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (4 | ) |
|
| — |
|
|
| (4 | ) |
Restricted stock canceled from take-private transaction (see Note 15) |
|
| (5,349,141 | ) |
|
| (53 | ) |
|
|
|
|
|
|
|
|
|
|
| (53 | ) |
|
|
|
|
| (53 | ) | ||||
Take-private transaction (see Note 1) |
|
| (58,059,259 | ) |
|
| (581 | ) |
|
| (988,242 | ) |
|
|
|
|
| (3,323,765 | ) |
|
| (4,312,588 | ) |
|
| — |
|
|
| (4,312,588 | ) | |
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 12,498 |
|
|
| 12,498 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (42,491 | ) |
|
| (42,491 | ) |
Balance at December 31, 2022 |
|
| 299,610,267 |
|
| $ | 2,996 |
|
| $ | — |
|
| $ | — |
|
| $ | 6,754,174 |
|
| $ | 6,757,170 |
|
| $ | 372,438 |
|
| $ | 7,129,608 |
|
The accompanying notes are an integral part of these consolidated financial statements.
53
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
Year Ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Cash flows from operating activities: | ||||||||||||
Net income (loss) | $ | 789,447 | $ | (399,679 | ) | $ | (353,668 | ) | ||||
Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||||||||||||
Depreciation, depletion, amortization and accretion | 1,670,838 | 1,709,567 | 1,746,454 | |||||||||
Property impairments | 237,370 | 237,292 | 402,131 | |||||||||
Non-cash (gain) loss on derivatives, net | (58,031 | ) | 156,621 | (21,532 | ) | |||||||
Stock-based compensation | 45,868 | 48,098 | 51,834 | |||||||||
Tax benefit from US tax reform legislation | (713,655 | ) | — | — | ||||||||
Provision (benefit) for deferred income taxes from operations | 88,056 | (209,836 | ) | (181,441 | ) | |||||||
Tax deficiency (benefit) from stock-based compensation | — | 9,828 | (13,177 | ) | ||||||||
Dry hole costs | 176 | 4,866 | 8,381 | |||||||||
Litigation settlement | 59,600 | — | — | |||||||||
Gain on sale of assets, net | (55,124 | ) | (304,489 | ) | (23,149 | ) | ||||||
Loss on extinguishment of debt | 554 | 26,055 | — | |||||||||
Other, net | 12,592 | 9,812 | 12,646 | |||||||||
Changes in assets and liabilities: | ||||||||||||
Accounts receivable | (329,811 | ) | (158,383 | ) | 524,973 | |||||||
Inventories | 14,517 | (17,836 | ) | 7,997 | ||||||||
Other current assets | 1,038 | 968 | 65,493 | |||||||||
Accounts payable trade | 137,339 | (14,404 | ) | (201,434 | ) | |||||||
Revenues and royalties payable | 158,982 | 30,455 | (85,754 | ) | ||||||||
Accrued liabilities and other | 21,368 | (883 | ) | (84,056 | ) | |||||||
Other noncurrent assets and liabilities | (2,018 | ) | (2,133 | ) | 1,403 | |||||||
Net cash provided by operating activities | 2,079,106 | 1,125,919 | 1,857,101 | |||||||||
Cash flows from investing activities: | ||||||||||||
Exploration and development | (1,931,942 | ) | (1,154,131 | ) | (3,042,747 | ) | ||||||
Purchase of producing crude oil and natural gas properties | (8,446 | ) | (5,008 | ) | (557 | ) | ||||||
Purchase of other property and equipment | (12,810 | ) | (5,375 | ) | (36,951 | ) | ||||||
Proceeds from sale of assets | 144,353 | 631,549 | 34,008 | |||||||||
Net cash used in investing activities | (1,808,845 | ) | (532,965 | ) | (3,046,247 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Credit facility borrowings | 1,302,000 | 1,691,000 | 2,001,000 | |||||||||
Repayment of credit facility | (2,019,000 | ) | (1,639,000 | ) | (1,313,000 | ) | ||||||
Proceeds from issuance of Senior Notes | 990,000 | — | — | |||||||||
Redemption of Senior Notes | — | (600,000 | ) | — | ||||||||
Premium on redemption of Senior Notes | — | (19,168 | ) | — | ||||||||
Proceeds from other debt | — | — | 500,000 | |||||||||
Repayment of other debt | (502,214 | ) | (2,144 | ) | (2,078 | ) | ||||||
Debt issuance costs | (1,999 | ) | (40 | ) | (4,597 | ) | ||||||
Repurchase of restricted stock for tax withholdings | (11,821 | ) | (8,593 | ) | (7,313 | ) | ||||||
Tax (deficiency) benefit from stock-based compensation | — | (9,828 | ) | 13,177 | ||||||||
Net cash (used in) provided by financing activities | (243,034 | ) | (587,773 | ) | 1,187,189 | |||||||
Effect of exchange rate changes on cash | 32 | (1 | ) | (10,961 | ) | |||||||
Net change in cash and cash equivalents | 27,259 | 5,180 | (12,918 | ) | ||||||||
Cash and cash equivalents at beginning of period | 16,643 | 11,463 | 24,381 | |||||||||
Cash and cash equivalents at end of period | $ | 43,902 | $ | 16,643 | $ | 11,463 |
|
| Year Ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
| |||
Net income (loss) |
| $ | 4,046,120 |
|
| $ | 1,666,408 |
|
| $ | (605,561 | ) |
Adjustments to reconcile net income (loss) to cash provided by operating activities: |
|
|
|
|
|
|
|
|
| |||
Depreciation, depletion, amortization and accretion |
|
| 1,886,491 |
|
|
| 1,893,106 |
|
|
| 1,882,458 |
|
Property impairments |
|
| 70,417 |
|
|
| 38,370 |
|
|
| 277,941 |
|
Non-cash (gain) loss on derivatives, net |
|
| 212,976 |
|
|
| (20,814 | ) |
|
| (13,492 | ) |
Stock/incentive-based compensation |
|
| 217,650 |
|
|
| 63,173 |
|
|
| 64,613 |
|
Provision (benefit) for deferred income taxes |
|
| 398,429 |
|
|
| 519,730 |
|
|
| (166,971 | ) |
Equity in net loss of affiliate |
|
| 1,489 |
|
|
| — |
|
|
| — |
|
Dry hole costs |
|
| 12,305 |
|
|
| — |
|
|
| — |
|
Net (gain) loss on sale of assets and other |
|
| 262 |
|
|
| (5,146 | ) |
|
| 187 |
|
(Gain) loss on extinguishment of debt |
|
| 403 |
|
|
| 290 |
|
|
| (35,719 | ) |
Other, net |
|
| 27,294 |
|
|
| 35,614 |
|
|
| 16,970 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
| |||
Accounts receivable |
|
| (372,529 | ) |
|
| (694,981 | ) |
|
| 332,128 |
|
Inventories |
|
| (67,478 | ) |
|
| (33,411 | ) |
|
| 12,859 |
|
Other current assets |
|
| (10,242 | ) |
|
| (2,144 | ) |
|
| 1,471 |
|
Accounts payable trade |
|
| 164,071 |
|
|
| 106,367 |
|
|
| (133,977 | ) |
Revenues and royalties payable |
|
| 253,286 |
|
|
| 298,552 |
|
|
| (143,260 | ) |
Accrued liabilities and other |
|
| 51,222 |
|
|
| 109,540 |
|
|
| (66,071 | ) |
Current income taxes liability |
|
| 152,149 |
|
|
| — |
|
|
| — |
|
Other noncurrent assets and liabilities |
|
| (4,625 | ) |
|
| (803 | ) |
|
| (1,272 | ) |
Net cash provided by operating activities |
|
| 7,039,690 |
|
|
| 3,973,851 |
|
|
| 1,422,304 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
| |||
Exploration and development |
|
| (2,838,075 | ) |
|
| (2,382,413 | ) |
|
| (1,408,149 | ) |
Purchase of producing crude oil and natural gas properties |
|
| (421,850 | ) |
|
| (2,548,575 | ) |
|
| (81,994 | ) |
Purchase of other property and equipment |
|
| (68,189 | ) |
|
| (66,598 | ) |
|
| (23,994 | ) |
Proceeds from sale of assets |
|
| 5,740 |
|
|
| 8,041 |
|
|
| 2,779 |
|
Contributions to unconsolidated affiliates |
|
| (212,294 | ) |
|
| — |
|
|
| — |
|
Net cash used in investing activities |
|
| (3,534,668 | ) |
|
| (4,989,545 | ) |
|
| (1,511,358 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
| |||
Credit facility borrowings |
|
| 3,886,000 |
|
|
| 1,663,000 |
|
|
| 2,052,000 |
|
Repayment of credit facility |
|
| (3,226,000 | ) |
|
| (1,323,000 | ) |
|
| (1,947,000 | ) |
Proceeds from issuance of Senior Notes |
|
| — |
|
|
| 1,587,776 |
|
|
| 1,485,000 |
|
Redemption and repurchase of Senior Notes |
|
| (31,829 | ) |
|
| (630,782 | ) |
|
| (1,343,250 | ) |
Premium and costs on redemption of Senior Notes |
|
| — |
|
|
| — |
|
|
| (25,173 | ) |
Proceeds from other debt |
|
| 750,000 |
|
|
| — |
|
|
| 26,000 |
|
Repayment of other debt |
|
| (2,326 | ) |
|
| (2,243 | ) |
|
| (6,679 | ) |
Debt issuance costs |
|
| (5,148 | ) |
|
| (12,082 | ) |
|
| (4,368 | ) |
Contributions from noncontrolling interests |
|
| 13,665 |
|
|
| 31,493 |
|
|
| 27,116 |
|
Distributions to noncontrolling interests |
|
| (40,685 | ) |
|
| (22,447 | ) |
|
| (13,809 | ) |
Repurchase of common stock prior to take-private transaction |
|
| (99,855 | ) |
|
| (123,924 | ) |
|
| (126,906 | ) |
Take-private transaction (see Note 1) |
|
| (4,312,642 | ) |
|
| — |
|
|
| — |
|
Repurchase of restricted stock for tax withholdings |
|
| (35,444 | ) |
|
| (12,804 | ) |
|
| (7,347 | ) |
Dividends paid on common stock |
|
| (283,838 | ) |
|
| (165,895 | ) |
|
| (18,460 | ) |
Net cash provided by (used in) financing activities |
|
| (3,388,102 | ) |
|
| 989,092 |
|
|
| 97,124 |
|
Net change in cash and cash equivalents |
|
| 116,920 |
|
|
| (26,602 | ) |
|
| 8,070 |
|
Cash and cash equivalents at beginning of period |
|
| 20,868 |
|
|
| 47,470 |
|
|
| 39,400 |
|
Cash and cash equivalents at end of period |
| $ | 137,788 |
|
| $ | 20,868 |
|
| $ | 47,470 |
|
The accompanying notes are an integral part of these consolidated financial statements.
54
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 1. Organization and Summary of Significant Accounting Policies
Description of the Company
Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is the exploration, development, management, and production of crude oil and natural gas exploration, development and productionassociated products with properties primarily located in the North, South, and East regions offour leading basins in the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
Take-Private Transaction
On October 16, 2022, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Pursuant to the Merger Agreement, on October 24, 2022 Merger Sub commenced a tender offer (the “Offer”) to purchase any and all of the outstanding shares of the Company’s estimated proved reservescommon stock for $74.28 per share in cash (the “Offer Price”), other than: (i) shares of common stock owned by Mr. Hamm, certain of his family members and their affiliated entities (collectively, the “Hamm Family”) and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans (collectively, the “Rollover Shares”).
The Offer expired at one minute after 11:59 p.m., New York City time, on November 21, 2022. As of the expiration of the Offer, a total of approximately 36.3 million shares were locatedvalidly tendered and not validly withdrawn pursuant to the Offer. In addition, notices of guaranteed delivery were delivered for approximately 3.4 million shares. Each condition to the Offer was satisfied and, on November 22, 2022, Merger Sub irrevocably accepted for payment all shares that were validly tendered and not withdrawn.
On November 22, 2022, immediately prior to the acceptance of shares for payment, Mr. Hamm contributed 100% of the capital stock of Merger Sub to the Company. In addition, following consummation of the Offer, Merger Sub merged with and into the Company, with the Company continuing as the surviving corporation wholly-owned by the Hamm Family (the “Merger”). At the effective time of the Merger, each remaining share of the Company not purchased in the North region. In recent years,Offer (other than (i) the Rollover Shares; (ii) shares owned by the Company has significantly expanded its operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 41%as treasury stock or owned by any wholly owned subsidiary of the Company, including shares irrevocably accepted by Merger Sub pursuant to the Offer; and (iii) shares held by a holder who properly demanded appraisal rights for such shares in accordance with Oklahoma law), was converted into the right to receive an amount in cash equal to the Offer Price, without interest and subject to any required tax withholding.
At the effective time of the Merger: (i) each share of the Company held by a member of the Hamm Family was converted into an identical number of newly issued shares of the Company, as the surviving corporation, having identical rights to the previously existing shares held by such holder, and such converted shares of the surviving corporation are the only capital stock of the surviving corporation outstanding following the Merger; and (ii) the Rollover Shares underlying each unvested restricted stock award issued under the Company’s crude oillong-term incentive plans that was outstanding immediately prior to the effective time were replaced with a restricted stock unit award issued by the Company that provides the holder of such previous award with the right to receive, on the date that such restricted stock award otherwise would have been settled, and natural gas production, 31%at the Company’s sole discretion, either a share of its crude oilthe Company, a cash award designed to provide substantially equivalent value, or any combination of the two, in each case, together with any unpaid dividends accrued on such restricted stock award.
A total of approximately 58.1 million shares of Continental’s common stock were purchased pursuant to the take-private transaction for total cash consideration of approximately $4.31 billion, inclusive of payments issued to holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law. The purchase of outstanding shares was funded by Continental through the use of approximately $2.2 billion of cash on hand, $1.3 billion of credit facility borrowings, and natural gas revenues, and 50%the execution of its estimated proved reservesa $750 million three-year term loan as further described in Note 8. Long-Term Debt. See the Consolidated Statements of andEquity for the year ended December 31, 2017.
55
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Following the completion of the Company’s total production and approximately 78% of its crude oil and natural gas revenues. Crude oil represents approximately 48%take-private transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (ii) our common stock was deregistered under Section 12(b) of the Company’s estimated proved reservesSecurities Exchange Act of 1934 as amended (the “Exchange Act”), and (iii) we suspended our reporting obligations under Section 15(d) of December 31, 2017.the Exchange Act. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer apply to us. We will continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures.
Basis of presentation of consolidated financial statements
The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and its subsidiaries, all ofentities in which are 100% owned, after all significant intercompanythe Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income (loss) and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements. For financial reporting purposes, the Company has one reportable segment due to the similar nature of its business, which is the exploration, development, and production of crude oil, natural gas, and natural gas liquids in the United States.
Investments in entities in which the Company has the ability to exercise significant influence, but does not control, are accounted for using the equity method of accounting. In applying the equity method, the investments are initially recognized at cost and are subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions, and distributions as applicable. See Note 18. Equity Investment for discussion of a strategic investment made by the Company in 2022 that is accounted for under the equity method.
The Company evaluated its December 31, 2022 financial statements for subsequent events through February 22, 2023, the date the financial statements were available to be issued.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties.
Cash and cash equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2017,2022, the Company had cash deposits in excess of federally insured amounts of approximately $42.5$136.4 million.
Accounts receivable
Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts.credit losses. Write-offs of noncollectable receivables have historically not been material. The Company’s allowance for doubtful accountscredit losses totaled $2.2$5.5 million and $3.0$2.8 million as of December 31, 20172022 and 2016, respectively, which is included in “Receivables
Concentration of credit risk
The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2017, sales to the Company’s two largest purchasers2022, no purchaser accounted for approximately 11% and 11%, respectively,more than 10% of the Company’s total crude oil, natural gas, and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil and natural gasliquids sales for 2017.2022. The Company generally does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.
Inventories
56
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company’s exploration and development activities. Crude oil inventories are valued at the lower of cost or marketnet realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.
The components of inventory as of December 31, 20172022 and 20162021 consisted of the following:
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Tubular goods and equipment |
| $ | 38,636 |
|
| $ | 12,506 |
|
Crude oil |
|
| 130,192 |
|
|
| 93,062 |
|
Natural gas |
|
| 4,436 |
|
|
| — |
|
Total |
| $ | 173,264 |
|
| $ | 105,568 |
|
December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Tubular goods and equipment | $ | 14,946 | $ | 15,243 | ||||
Crude oil | 82,460 | 96,744 | ||||||
Total | $ | 97,406 | $ | 111,987 |
Crude oil and natural gas properties
The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance repairs and costs of injectionrepairs are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.
Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs
Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, certain waste water disposal costs, utility costs, certain workover-related costs, and materials and supplies utilized in the Company’s operations.
Service property and equipment
Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering and recycling systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred.
Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows:
Service property and equipment | Useful Lives | |
Automobiles and aircraft | 5-10 | |
Machinery and equipment | 6-30 | |
Gathering and recycling systems | 15-30 | |
Storage tanks | 10-30 | |
Office and computer equipment, software, furniture and fixtures | 3-25 | |
Buildings and improvements | 4-40 |
Depreciation, depletion and amortization
Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based
57
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. UnitSales of productionproved properties constituting a part of an amortization base are accounted for as normal retirements with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate. Unit-of-production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Asset retirement obligations
The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.
The Company’s primary asset retirement obligations relate to future plugging and abandonment costs and related disposal of facilities on its crude oil and natural gas properties.The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 20152020 through December 31, 2017:
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Asset retirement obligations at January 1 |
| $ | 219,824 |
|
| $ | 179,676 |
|
| $ | 153,673 |
|
Accretion expense |
|
| 12,857 |
|
|
| 11,125 |
|
|
| 9,393 |
|
Revisions (1) |
|
| (6,672 | ) |
|
| (1,291 | ) |
|
| 10,743 |
|
Plus: Additions for new assets |
|
| 37,413 |
|
|
| 32,351 |
|
|
| 7,048 |
|
Less: Plugging costs and sold assets |
|
| (2,335 | ) |
|
| (2,037 | ) |
|
| (1,181 | ) |
Total asset retirement obligations at December 31 |
| $ | 261,087 |
|
| $ | 219,824 |
|
| $ | 179,676 |
|
Less: Current portion of asset retirement obligations at December 31 (2) |
|
| 3,935 |
|
|
| 4,123 |
|
|
| 2,482 |
|
Non-current portion of asset retirement obligations at December 31 |
| $ | 257,152 |
|
| $ | 215,701 |
|
| $ | 177,194 |
|
In thousands | 2017 | 2016 | 2015 | |||||||||
Asset retirement obligations at January 1 | $ | 96,178 | $ | 102,909 | $ | 76,708 | ||||||
Accretion expense | 5,886 | 6,086 | 4,740 | |||||||||
Revisions (1) | 7,801 | (12,755 | ) | 15,068 | ||||||||
Plus: Additions for new assets | 6,884 | 2,692 | 7,404 | |||||||||
Less: Plugging costs and sold assets | (2,343 | ) | (2,754 | ) | (1,011 | ) | ||||||
Total asset retirement obligations at December 31 | $ | 114,406 | $ | 96,178 | $ | 102,909 | ||||||
Less: Current portion of asset retirement obligations at December 31 (2) | 2,612 | 1,742 | 1,658 | |||||||||
Non-current portion of asset retirement obligations at December 31 | $ | 111,794 | $ | 94,436 | $ | 101,251 |
As of December 31, 20172022 and 2016,2021, net property and equipment on the consolidated balance sheets included $40.3$96.5 million and $34.0$72.8 million, respectively, of net asset retirement costs.
Asset impairment
Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value.
Impairment losses for non-producingunproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
58
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Debt issuance costs
Costs incurred in connection with the execution of the Company’s notenotes payable, and revolving credit facility, term loan and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company’s various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.
The Company had aggregate capitalized costs of $58.2$56.3 million and $55.9$60.6 million (net of accumulated amortization of $65.9$46.3 million and $56.8$36.9 million) relating to its long-term debt at December 31, 20172022 and 2016,2021, respectively.
Unamortized capitalized costs associated with the Company’s Notes, and note payable, and term loan totaled $55.0$46.8 million and $50.4$50.9 million at December 31, 20172022 and 2016,2021, respectively, and are reflected as a reduction of “Long-term debt, net of current portion” on the consolidated balance sheets. The increase in 2017 resulted from the capitalization of costs incurred in connection with the Company’s issuance of 4.375% Senior Notes due 2028 as discussed in
Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $3.2$9.4 million and $5.5$9.7 million at December 31, 20172022 and 2016,2021, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets.
For the years ended December 31, 2017, 20162022, 2021 and 2015,2020, the Company recognized amortization expense associated with capitalized debt issuance costs of $9.1$9.3 million, $9.8$7.2 million, and $8.9$7.8 million, respectively, which are reflected in “Interest expense” on the consolidated statements of comprehensive income (loss).
Derivative instruments
The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss). Gains and losses on crude oil and natural gas derivatives are reflected in under the caption “
Fair value of financial instruments
The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See
NoteIncome taxes
Income taxes are accounted for using the asset and liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end.period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law, which among other things reduces the federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate. See
The Company establishes a valuation allowance for deferred tax assets is recorded whenif it believes it is more likely than not that the benefit from thesome or all of its deferred tax assetassets will not be realized. The Company recordedSignificant judgment is applied in evaluating the need for and the magnitude of appropriate valuation allowances of $0.4 million, $1.0 million, and $13.5 million for the years ended December 31, 2017, 2016, and 2015, respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiaryassets. See Note 11. Income Taxes for which the Company does not expectadditional information.
59
Continental Resources, Inc. and Subsidiaries
Notes to realize a benefit.
Earnings per share attributable to Continental Resources
Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. InPrior to the Hamm Family's take-private transaction, in periods where the Company hashad net income, diluted earnings per share reflectsreflected the potential dilution of non-vested restricted stock awards, which arewas calculated using the treasury stock method.The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2017, 20162022, 2021, and 2015.
|
| Year ended December 31, |
| |||||||||
In thousands, except per share data |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Net income (loss) attributable to Continental Resources (numerator) |
| $ | 4,024,558 |
|
| $ | 1,660,968 |
|
| $ | (596,869 | ) |
Weighted average shares (denominator): |
|
|
|
|
|
|
|
|
| |||
Weighted average shares - basic |
|
| 351,392 |
|
|
| 360,434 |
|
|
| 361,538 |
|
Non-vested restricted stock and restricted stock units (1) |
|
| — |
|
|
| 4,019 |
|
|
| — |
|
Weighted average shares - diluted |
|
| 351,392 |
|
|
| 364,453 |
|
|
| 361,538 |
|
Net income (loss) per share attributable to Continental Resources: |
|
|
|
|
|
|
|
|
| |||
Basic |
| $ | 11.45 |
|
| $ | 4.61 |
|
| $ | (1.65 | ) |
Diluted |
| $ | 11.45 |
|
| $ | 4.56 |
|
| $ | (1.65 | ) |
Year ended December 31, | ||||||||||||
In thousands, except per share data | 2017 | 2016 | 2015 | |||||||||
Net income (loss) (numerator) (1) | $ | 789,447 | $ | (399,679 | ) | $ | (353,668 | ) | ||||
Weighted average shares (denominator): | ||||||||||||
Weighted average shares - basic | 371,066 | 370,380 | 369,540 | |||||||||
Non-vested restricted stock (2) | 2,702 | — | — | |||||||||
Weighted average shares - diluted | 373,768 | 370,380 | 369,540 | |||||||||
Net income (loss) per share: (1) | ||||||||||||
Basic | $ | 2.13 | $ | (1.08 | ) | $ | (0.96 | ) | ||||
Diluted | $ | 2.11 | $ | (1.08 | ) | $ | (0.96 | ) |
Note 2. Property Acquisitions
2022
In March 2022, the Company acquired oil and gas properties in the Powder River Basin for cash consideration of $403 million, representing a $450 million purchase price less customary closing adjustments made pursuant to the acquisition agreement. The acquisition was accounted for as an asset acquisition under ASC Topic 805—Business Combinations and included approximately 172,000 net leasehold acres and producing properties with production totaling approximately 18,000 net barrels of oil equivalent per day at the time of closing. Of the purchase price, $381.3 million was allocated to proved properties and $21.7 million was allocated to unproved properties. The Company recognized approximately $15.3 million of asset retirement obligations, $31.3 million of assumed production and ad valorem tax payment obligations, and $10.1 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties.
In April 2022, the Company acquired oil and gas properties in the Permian Basin for cash consideration of $197.0 million, representing a $200 million purchase price less customary closing adjustments made pursuant to the acquisition agreement. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and was comprised primarily of undeveloped leasehold acreage with an immaterial amount of production. Nearly all of the purchase price was allocated to unproved properties.
2021
Permian Basin Acquisition
In December 2021, the Company acquired oil and gas assets and properties from certain subsidiaries of Pioneer Natural Resources Company pursuant to a purchase and sale agreement in which the Company purchased: (a) 100% of the issued and outstanding limited liability company interests of Jagged Peak Energy LLC, which in turn owned 100% of the issued and outstanding limited liability company interests of Parsley SoDe Water LLC; and (b) certain oil and gas assets and properties in the Permian Basin (collectively, the “Pioneer Acquisition”). The properties included approximately 92,000 net leasehold acres, approximately 50,000 net royalty acres in the same area normalized to a 1/8th royalty, production totaling approximately 42,000 net barrels of oil equivalent per day at the time of closing, and extensive water infrastructure.
The purchase price paid to the sellers was approximately $3.06 billion in cash, representing a $3.25 billion purchase price less customary closing adjustments made pursuant to the agreement. The Company funded the purchase price through a combination of cash on hand, utilization of credit facility borrowing capacity, and the issuance of senior notes.
60
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Pioneer Acquisition was accounted for using the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company’s operations in Canada are currently immaterial. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income (loss)” within shareholders’ equity on the consolidated balance sheets.
The Pioneer Acquisition contributed $29.4 million of revenues and $14.1 million ($0.010.04 per basic and diluted share) of tax deficienciesnet income to the Company's consolidated results during the period of ownership from stock-based compensation asDecember 21, 2021 to December 31, 2021, excluding transaction expenses. The Company incurred $13.9 million of expenses in connection with the transaction which are reflected in the caption “Transaction costs” in the consolidated statements of income tax expense(loss) for the year ended December 31, 2017 under2021.
The table below summarizes the new standard, whichCompany’s pro forma results as if the Pioneer Acquisition and associated increase in debt described in Note 8. Long-Term Debt had been completed on January 1, 2020 and were combined with the Company's historical results. The following pro forma information is reflected in “Benefitunaudited, is provided for income taxes”informational purposes only, and does not represent actual results that would have occurred if the Pioneer Acquisition was completed on January 1, 2020, nor are they indicative of future results.
|
| Year Ended December 31, |
| |||||
In millions |
| 2021 |
|
| 2020 |
| ||
Pro forma combined total revenues |
| $ | 6,657 |
|
| $ | 3,174 |
|
Pro forma combined net income (loss) attributable to Continental |
| $ | 2,097 |
|
| $ | (481 | ) |
Powder River Basin Acquisitions
In March 2021, the Company acquired oil and gas properties in the consolidated statementsPowder River Basin for cash consideration of comprehensive income (loss).
In November 2021, the Company acquired oil and gas properties in the Powder River Basin for cash consideration of $246.8 million. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and included approximately 72,000 net acres and immaterial amounts of January 1, 2017, which had no significant impact onproduction. Of the Company’s financial statements aspurchase price, $27 million was allocated to proved properties and $220 million was allocated to unproved properties. The Company recognized approximately $0.5 million of asset retirement obligations and for the year ended December 31, 2017.
2020
In October 2020, the Company acquired oil and gas properties in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition.
Note 2.3. Supplemental Cash Flow Information
The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
|
| Year ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Supplemental cash flow information: |
|
|
|
|
|
|
|
|
| |||
Cash paid for interest |
| $ | 279,571 |
|
| $ | 214,727 |
|
| $ | 256,633 |
|
Cash paid for income taxes (1) |
|
| 470,147 |
|
|
| 3 |
|
|
| 4 |
|
Cash received for income tax refunds |
|
| 16 |
|
|
| 58 |
|
|
| 9,600 |
|
Non-cash investing activities: |
|
|
|
|
|
|
|
|
| |||
Asset retirement obligation additions and revisions, net |
|
| 30,741 |
|
|
| 31,060 |
|
|
| 17,791 |
|
61
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Year ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Supplemental cash flow information: | ||||||||||||
Cash paid for interest | $ | 281,058 | $ | 316,116 | $ | 301,743 | ||||||
Cash paid for income taxes | 2 | 2 | 30 | |||||||||
Cash received for income tax refunds | 257 | 174 | 61,403 | |||||||||
Non-cash investing activities: | ||||||||||||
Asset retirement obligation additions and revisions, net | 14,685 | (10,063 | ) | 22,472 |
As of December 31, 20172022 and 2016,2021, the Company had $302.8$344.9 million and $223.6$242.9 million, respectively, of accrued capital expenditures included in “Net property and equipment” andwith an offsetting amount in “Accounts payable trade” in the consolidated balance sheets.
As of December 31, 2022 and 2021, the Company had $0.5 million and $1.7 million, respectively, of accrued contributions from noncontrolling interests included in “Receivables–Joint interest and other” with an offsetting amount in “Equity–Noncontrolling interests” in the consolidated balance sheets.
As of December 31, 2022 and 2021, the Company had $4.3 million and $2.5 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" with an offsetting amount in “Equity–Noncontrolling interests” in the consolidated balance sheets.
Note 3.4. Net Property and Equipment
Net property and equipment includes the following at December 31, 20172022 and 2016.
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Proved crude oil and natural gas properties |
| $ | 34,741,054 |
|
| $ | 31,613,656 |
|
Unproved crude oil and natural gas properties |
|
| 1,513,627 |
|
|
| 1,358,673 |
|
Service properties, equipment and other |
|
| 549,528 |
|
|
| 484,989 |
|
Total property and equipment |
|
| 36,804,209 |
|
|
| 33,457,318 |
|
Accumulated depreciation, depletion and amortization |
|
| (18,332,295 | ) |
|
| (16,481,853 | ) |
Net property and equipment |
| $ | 18,471,914 |
|
| $ | 16,975,465 |
|
December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Proved crude oil and natural gas properties | $ | 21,362,199 | $ | 19,802,395 | ||||
Unproved crude oil and natural gas properties | 365,413 | 429,562 | ||||||
Service properties, equipment and other | 290,111 | 301,788 | ||||||
Total property and equipment | 22,017,723 | 20,533,745 | ||||||
Accumulated depreciation, depletion and amortization | (9,083,934 | ) | (7,652,518 | ) | ||||
Net property and equipment | $ | 12,933,789 | $ | 12,881,227 |
Note 4.5. Accrued Liabilities and Other
Accrued liabilities and other includes the following at December 31, 20172022 and 2016:
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Prepaid advances from joint interest owners |
| $ | 15,575 |
|
| $ | 18,964 |
|
Accrued compensation |
|
| 81,646 |
|
|
| 82,844 |
|
Accrued production taxes, ad valorem taxes and other non-income taxes |
|
| 145,436 |
|
|
| 90,597 |
|
Accrued interest |
|
| 83,724 |
|
|
| 75,983 |
|
Current portion of asset retirement obligations |
|
| 3,935 |
|
|
| 4,123 |
|
Other |
|
| 13,461 |
|
|
| 13,229 |
|
Accrued liabilities and other |
| $ | 343,777 |
|
| $ | 285,740 |
|
December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Prepaid advances from joint interest owners | $ | 34,511 | $ | 57,861 | ||||
Accrued compensation | 65,308 | 38,046 | ||||||
Accrued production taxes, ad valorem taxes and other non-income taxes | 40,611 | 22,053 | ||||||
Accrued interest | 55,282 | 52,657 | ||||||
Accrued litigation settlement (see Note 10) | 59,600 | — | ||||||
Current portion of asset retirement obligations | 2,612 | 1,742 | ||||||
Other | 2,150 | 4,411 | ||||||
Accrued liabilities and other | $ | 260,074 | $ | 176,770 |
Note 5.6. Derivative Instruments
From time to time the Company may utilize crude oil and natural gas swap and collarenters into derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.
Period and Type of Contract | MMBtus | Swaps Weighted Average Price | ||||||
January 2018 - March 2018 | ||||||||
Swaps - Henry Hub | 6,300,000 | $ | 3.28 |
Year ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Cash received (paid) on derivatives: | ||||||||||||
Natural gas fixed price swaps | $ | 40,095 | $ | 88,823 | $ | 39,670 | ||||||
Natural gas collars | (10,539 | ) | — | 29,883 | ||||||||
Cash received on derivatives, net | 29,556 | 88,823 | 69,553 | |||||||||
Non-cash gain (loss) on derivatives: | ||||||||||||
Crude oil written call options | — | 38 | 4,715 | |||||||||
Natural gas fixed price swaps | 18,960 | (120,784 | ) | 41,828 | ||||||||
Natural gas collars | 43,131 | (39,936 | ) | (25,011 | ) | |||||||
Non-cash gain (loss) on derivatives, net | 62,091 | (160,682 | ) | 21,532 | ||||||||
Gain (loss) on crude oil and natural gas derivatives, net | $ | 91,647 | $ | (71,859 | ) | $ | 91,085 |
62
Continental Resources, Inc. and recognizedSubsidiaries
Notes to Consolidated Financial Statements
At December 31, 2022 the changes in fair valueCompany had outstanding derivative contracts as set forth in the consolidated statementstables below.
Natural gas derivatives |
|
|
|
|
| Weighted Average Hedge Price ($/MMBtu) |
| ||||||||||||||||||
Period and Type of Contract |
| Average Volumes Hedged |
| Basis |
|
| Swaps |
|
| Sold |
|
| Floor |
|
| Ceiling |
| ||||||||
January 2023 - December 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Basis Swaps - NGPL TXOK |
|
| 75,000 |
| MMBtus/day |
| $ | (0.17 | ) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
January 2023 - March 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Collars - Henry Hub |
|
| 360,000 |
| MMBtus/day |
|
|
|
|
|
|
|
|
|
| $ | 3.91 |
|
| $ | 5.45 |
| |||
Three-way collars - Henry Hub |
|
| 50,000 |
| MMBtus/day |
|
|
|
|
|
|
| $ | 3.00 |
|
| $ | 4.32 |
|
| $ | 5.00 |
| ||
Swaps - Henry Hub |
|
| 210,000 |
| MMBtus/day |
|
|
|
| $ | 4.26 |
|
|
|
|
|
|
|
|
|
| ||||
Swaps - WAHA |
|
| 55,000 |
| MMBtus/day |
|
|
|
| $ | 2.81 |
|
|
|
|
|
|
|
|
|
| ||||
April 2023 - September 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Swaps - Henry Hub |
|
| 405,000 |
| MMBtus/day |
|
|
|
| $ | 3.28 |
|
|
|
|
|
|
|
|
|
| ||||
Swaps - WAHA |
|
| 55,000 |
| MMBtus/day |
|
|
|
| $ | 2.81 |
|
|
|
|
|
|
|
|
|
| ||||
October 2023 - December 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Collars - Henry Hub |
|
| 200,000 |
| MMBtus/day |
|
|
|
|
|
|
|
|
|
| $ | 3.12 |
|
| $ | 4.09 |
| |||
Swaps - Henry Hub |
|
| 210,000 |
| MMBtus/day |
|
|
|
| $ | 3.51 |
|
|
|
|
|
|
|
|
|
| ||||
Swaps - WAHA |
|
| 55,000 |
| MMBtus/day |
|
|
|
| $ | 2.81 |
|
|
|
|
|
|
|
|
|
| ||||
January 2024 - December 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Collars - Henry Hub |
|
| 50,000 |
| MMBtus/day |
|
|
|
|
|
|
|
|
|
| $ | 3.12 |
|
| $ | 4.09 |
| |||
Swaps - Henry Hub |
|
| 325,000 |
| MMBtus/day |
|
|
|
| $ | 3.31 |
|
|
|
|
|
|
|
|
|
| ||||
Swaps - WAHA |
|
| 25,000 |
| MMBtus/day |
|
|
|
| $ | 3.43 |
|
|
|
|
|
|
|
|
|
| ||||
January 2025 - December 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Swaps - Henry Hub |
|
| 60,000 |
| MMBtus/day |
|
|
|
| $ | 3.75 |
|
|
|
|
|
|
|
|
|
| ||||
January 2026 - December 2026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Swaps - Henry Hub |
|
| 50,000 |
| MMBtus/day |
|
|
|
| $ | 4.42 |
|
|
|
|
|
|
|
|
|
|
Crude oil derivatives |
|
|
|
|
|
| Weighted Average |
| ||||||
Period and Type of Contract |
| Average Volumes Hedged |
| Roll Swaps |
|
| Fixed Swaps |
| ||||||
January 2023 - December 2023 |
|
|
|
|
|
|
|
|
|
|
| |||
Roll Swaps - NYMEX |
|
| 12,000 |
|
| Bbls/day |
| $ | 1.07 |
|
|
|
| |
Fixed Swaps - WTI |
|
| 8,000 |
|
| Bbls/day |
|
|
|
| $ | 83.19 |
|
63
Table of comprehensive income (loss) under the caption “Operating costsContents
Continental Resources, Inc. and expenses—Net gain on sale of assetsSubsidiaries
Notes to Consolidated Financial Statements
Derivative gains and other.”
Cash receipts and payments in the following table reflect the gains or losses on diesel fuel derivativesderivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of diesel fuel derivativesderivative instruments which continued to be held at period end if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
|
| Year ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Cash received (paid) on derivatives: |
|
|
|
|
|
|
|
|
| |||
Crude oil fixed price swaps |
| $ | — |
|
| $ | (44,463 | ) |
| $ | (31,179 | ) |
Crude oil collars |
|
| — |
|
|
| (9,365 | ) |
|
| — |
|
Crude oil NYMEX roll swaps |
|
| (9,234 | ) |
|
| (163 | ) |
|
| — |
|
Natural gas basis swaps |
|
| 9,674 |
|
|
| — |
|
|
| — |
|
Natural gas WAHA swaps |
|
| (16,350 | ) |
|
| — |
|
|
| — |
|
Natural gas fixed price swaps |
|
| (353,326 | ) |
|
| (84,141 | ) |
|
| 1,071 |
|
Natural gas collars |
|
| (66,596 | ) |
|
| (11,546 | ) |
|
| 1,958 |
|
Natural gas three-way collars |
|
| (22,287 | ) |
|
| — |
|
|
| — |
|
Cash received (paid) on derivatives, net |
|
| (458,119 | ) |
|
| (149,678 | ) |
|
| (28,150 | ) |
Non-cash gain (loss) on derivatives: |
|
|
|
|
|
|
|
|
| |||
Crude oil collars |
|
| — |
|
|
| 227 |
|
|
| (227 | ) |
Crude oil fixed price swaps |
|
| 11,696 |
|
|
| — |
|
|
| — |
|
Crude oil NYMEX roll swaps |
|
| 1,879 |
|
|
| 957 |
|
|
| — |
|
Natural gas basis swaps |
|
| 9,088 |
|
|
| (177 | ) |
|
| — |
|
Natural gas WAHA swaps |
|
| 19,386 |
|
|
| — |
|
|
| — |
|
Natural gas fixed price swaps |
|
| (219,388 | ) |
|
| 25,565 |
|
|
| 2,043 |
|
Natural gas collars |
|
| (34,303 | ) |
|
| (7,690 | ) |
|
| 11,676 |
|
Natural gas three-way collars |
|
| (1,334 | ) |
|
| 1,932 |
|
|
| — |
|
Non-cash gain (loss) on derivatives, net |
|
| (212,976 | ) |
|
| 20,814 |
|
|
| 13,492 |
|
Loss on derivative instruments, net |
| $ | (671,095 | ) |
| $ | (128,864 | ) |
| $ | (14,658 | ) |
Year ended December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Cash received on diesel fuel derivatives | $ | 2,845 | $ | 699 | ||||
Non-cash gain (loss) on diesel fuel derivatives | (4,060 | ) | 4,060 | |||||
Gain (loss) on diesel fuel derivatives, net | $ | (1,215 | ) | $ | 4,759 |
Balance sheet offsetting of derivative assets and liabilities
The Company’s derivative contracts are recorded at fair value in the consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”,assets,” “Derivative liabilities”,assets, noncurrent,” “Derivative liabilities,” and “Noncurrent derivative liabilities”,“Derivative liabilities, noncurrent,” as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the consolidated balance sheets.
The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented,at December 31, 2022, all at fair value.
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Commodity derivative assets: |
|
|
|
|
|
| ||
Gross amounts of recognized assets |
| $ | 50,559 |
|
| $ | 42,903 |
|
Gross amounts offset on balance sheet |
|
| (7,731 | ) |
|
| (7,381 | ) |
Net amounts of assets on balance sheet |
|
| 42,828 |
|
|
| 35,522 |
|
Commodity derivative liabilities: |
|
|
|
|
|
| ||
Gross amounts of recognized liabilities |
|
| (229,230 | ) |
|
| (8,598 | ) |
Gross amounts offset on balance sheet |
|
| 7,731 |
|
|
| 7,381 |
|
Net amounts of liabilities on balance sheet |
| $ | (221,499 | ) |
| $ | (1,217 | ) |
64
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Commodity derivative assets: | ||||||||
Gross amounts of recognized assets | $ | 2,603 | $ | 4,061 | ||||
Gross amounts offset on balance sheet | — | — | ||||||
Net amounts of assets on balance sheet | 2,603 | 4,061 | ||||||
Commodity derivative liabilities: | ||||||||
Gross amounts of recognized liabilities | — | (59,489 | ) | |||||
Gross amounts offset on balance sheet | — | — | ||||||
Net amounts of liabilities on balance sheet | $ | — | $ | (59,489 | ) |
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets.
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Derivative assets |
| $ | 39,280 |
|
| $ | 22,334 |
|
Derivative assets, noncurrent |
|
| 3,548 |
|
|
| 13,188 |
|
Net amounts of assets on balance sheet |
|
| 42,828 |
|
|
| 35,522 |
|
Derivative liabilities |
|
| (88,136 | ) |
|
| (899 | ) |
Derivative liabilities, noncurrent |
|
| (133,363 | ) |
|
| (318 | ) |
Net amounts of liabilities on balance sheet |
|
| (221,499 | ) |
|
| (1,217 | ) |
Total derivative assets (liabilities), net |
| $ | (178,671 | ) |
| $ | 34,305 |
|
December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Derivative assets | $ | 2,603 | $ | 4,061 | ||||
Noncurrent derivative assets | — | — | ||||||
Net amounts of assets on balance sheet | 2,603 | 4,061 | ||||||
Derivative liabilities | — | (59,489 | ) | |||||
Noncurrent derivative liabilities | — | — | ||||||
Net amounts of liabilities on balance sheet | — | (59,489 | ) | |||||
Total derivative assets (liabilities), net | $ | 2,603 | $ | (55,428 | ) |
Note 6.7. Fair Value Measurements
The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
Assets and liabilities measuredLiabilities Measured at fair valueFair Value on a recurring basis
The Company’s derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.
65
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following tables summarize the valuation of financialderivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 20172022 and 2016.2021.
|
| Fair value measurements at December 31, 2022 using: |
|
|
|
| ||||||||||
In thousands |
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
Derivative assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Crude oil fixed price swaps |
| $ | — |
|
| $ | 11,696 |
|
| $ | — |
|
| $ | 11,696 |
|
Crude oil NYMEX roll swaps |
|
| — |
|
|
| 2,836 |
|
|
| — |
|
|
| 2,836 |
|
Natural gas basis swaps |
|
| — |
|
|
| 8,910 |
|
|
| — |
|
|
| 8,910 |
|
Natural gas WAHA swaps |
|
| — |
|
|
| 19,386 |
|
|
| — |
|
|
| 19,386 |
|
Natural gas fixed price swaps |
|
| — |
|
|
| (191,779 | ) |
|
| — |
|
|
| (191,779 | ) |
Natural gas collars |
|
| — |
|
|
| (30,318 | ) |
|
| — |
|
|
| (30,318 | ) |
Natural gas three-way collars |
|
| — |
|
|
| 598 |
|
|
| — |
|
|
| 598 |
|
Total |
| $ | — |
|
| $ | (178,671 | ) |
| $ | — |
|
| $ | (178,671 | ) |
|
| Fair value measurements at December 31, 2021 using: |
|
|
|
| ||||||||||
In thousands |
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
Derivative assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Natural gas fixed price swaps |
| $ | — |
|
| $ | 27,608 |
|
| $ | — |
|
| $ | 27,608 |
|
Natural gas basis swaps |
|
| — |
|
|
| (177 | ) |
|
| — |
|
|
| (177 | ) |
Natural gas collars |
|
| — |
|
|
| 3,986 |
|
|
| — |
|
|
| 3,986 |
|
Natural gas three-way collars |
|
| — |
|
|
| 1,931 |
|
|
| — |
|
|
| 1,931 |
|
Crude oil NYMEX roll swaps |
|
| — |
|
|
| 957 |
|
|
| — |
|
|
| 957 |
|
Total |
| $ | — |
|
| $ | 34,305 |
|
| $ | — |
|
| $ | 34,305 |
|
Fair value measurements at December 31, 2017 using: | ||||||||||||||||
In thousands | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Derivative assets: | ||||||||||||||||
Swaps | $ | — | $ | 2,603 | $ | — | $ | 2,603 | ||||||||
Total | $ | — | $ | 2,603 | $ | — | $ | 2,603 |
Fair value measurements at December 31, 2016 using: | ||||||||||||||||
In thousands | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Derivative liabilities: | ||||||||||||||||
Swaps | $ | — | $ | (12,297 | ) | $ | — | $ | (12,297 | ) | ||||||
Collars | — | (43,131 | ) | — | (43,131 | ) | ||||||||||
Total | $ | — | $ | (55,428 | ) | $ | — | $ | (55,428 | ) |
Assets measuredMeasured at fair valueFair Value on a nonrecurring basis
Certain assets are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.
Asset impairments –
Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties.Unobservable inputs to the Company’s fair value assessmentassessments are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
For the year ended December 31, 2017,2022, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties amounted to $82.3Such impairments totaled $17.5 million, for 2017, which reflectprimarily reflected fair value adjustments on a property in an emerging play and on legacy properties in the Arkoma Woodford field ($81.2 million) and various non-core areas in the North and South regions ($1.1 million).Red River Units. The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72$2.1 million.
For the year ended December 31, 2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairment was recorded for the Company's proved crude oil and natural gas properties in 2021.
For the year ended December 31, 2020, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Such impairments totaled $207.1 million, which reflected fair value
66
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
adjustments on legacy properties in the Red River Units totaling $168.1 million and various non-core properties in the North and South regions totaling $14.5 million. The impaired properties were written down to their estimated fair value at the time of impairment of $145.7 million. Impairments for 2020 also include a $24.5 million impairment recognized in the first quarter of 2020 to reduce the Company’s crude oil inventory to estimated net realizable value at the time of impairment.
Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2017, 2016,2022, 2021, and 2015,2020, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.
The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss).
|
| Year ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Proved property and inventory impairments |
| $ | 17,520 |
|
| $ | — |
|
| $ | 207,119 |
|
Unproved property impairments |
|
| 52,897 |
|
|
| 38,370 |
|
|
| 70,822 |
|
Total |
| $ | 70,417 |
|
| $ | 38,370 |
|
| $ | 277,941 |
|
Year ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Proved property impairments | $ | 82,340 | $ | 2,895 | $ | 138,878 | ||||||
Unproved property impairments | 155,030 | 234,397 | 263,253 | |||||||||
Total | $ | 237,370 | $ | 237,292 | $ | 402,131 |
Financial instruments not recordedInstruments Not Recorded at fair value
The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements.
December 31, 2017 | December 31, 2016 | |||||||||||||||
In thousands | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Debt: | ||||||||||||||||
Revolving credit facility (1) | $ | 188,000 | $ | 188,000 | $ | 905,000 | $ | 905,000 | ||||||||
Term loan (1) | — | — | 498,865 | 500,000 | ||||||||||||
Note payable | 9,974 | 9,900 | 12,176 | 10,200 | ||||||||||||
5% Senior Notes due 2022 | 1,997,576 | 2,040,000 | 1,997,188 | 2,020,400 | ||||||||||||
4.5% Senior Notes due 2023 | 1,486,690 | 1,526,800 | 1,484,524 | 1,474,800 | ||||||||||||
3.8% Senior Notes due 2024 | 992,036 | 988,800 | 990,964 | 929,400 | ||||||||||||
4.375% Senior Notes due 2028 (1) | 988,061 | 987,200 | — | — | ||||||||||||
4.9% Senior Notes due 2044 | 691,354 | 679,900 | 691,199 | 607,600 | ||||||||||||
Total debt | $ | 6,353,691 | $ | 6,420,600 | $ | 6,579,916 | $ | 6,447,400 |
|
| December 31, 2022 |
|
| December 31, 2021 |
| ||||||||||
In thousands |
| Carrying Amount |
|
| Estimated Fair Value |
|
| Carrying Amount |
|
| Estimated Fair Value |
| ||||
Debt: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Credit facility |
| $ | 1,160,000 |
|
| $ | 1,160,000 |
|
| $ | 500,000 |
|
| $ | 500,000 |
|
Term Loan |
|
| 747,073 |
|
|
| 747,073 |
|
|
| — |
|
|
| — |
|
Notes payable |
|
| 20,041 |
|
|
| 18,300 |
|
|
| 22,356 |
|
|
| 22,000 |
|
4.5% Senior Notes due 2023 |
|
| 635,648 |
|
|
| 633,600 |
|
|
| 648,078 |
|
|
| 670,200 |
|
3.8% Senior Notes due 2024 |
|
| 891,404 |
|
|
| 867,400 |
|
|
| 908,061 |
|
|
| 950,000 |
|
2.268% Senior Notes due 2026 |
|
| 794,062 |
|
|
| 693,100 |
|
|
| 792,621 |
|
|
| 795,200 |
|
4.375% Senior Notes due 2028 |
|
| 993,076 |
|
|
| 917,200 |
|
|
| 991,880 |
|
|
| 1,082,100 |
|
5.75% Senior Notes due 2031 |
|
| 1,483,843 |
|
|
| 1,412,300 |
|
|
| 1,482,319 |
|
|
| 1,769,600 |
|
2.875% Senior Notes due 2032 |
|
| 792,238 |
|
|
| 600,900 |
|
|
| 791,521 |
|
|
| 780,500 |
|
4.9% Senior Notes due 2044 |
|
| 692,255 |
|
|
| 527,900 |
|
|
| 692,056 |
|
|
| 781,500 |
|
Total debt |
| $ | 8,209,640 |
|
| $ | 7,577,773 |
|
| $ | 6,828,892 |
|
| $ | 7,351,100 |
|
The fair value of 4.375% Senior Notes due 2028credit facility and used the proceeds therefrom to repay in full and terminate its term loan and to repay a portion of the borrowings outstanding under its revolving credit facility. See Note 7. Long-Term Debt for further discussion.
The fair value of the notenotes payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the notenotes payable and an assumed discount rate. The fair value of the notenotes payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the notenotes payable is classified as Level 3 in the fair value hierarchy.
The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), the 4.375% Senior Notes due 2028 (“2028 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”)Company’s senior notes are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.
67
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 7.8. Long-Term Debt
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $44.3$49.6 million and $37.3$54.2 million at December 31, 20172022 and 2016,2021, respectively, consists of the following.
December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Revolving credit facility | $ | 188,000 | $ | 905,000 | ||||
Term loan | — | 498,865 | ||||||
Note payable | 9,974 | 12,176 | ||||||
5% Senior Notes due 2022 | 1,997,576 | 1,997,188 | ||||||
4.5% Senior Notes due 2023 | 1,486,690 | 1,484,524 | ||||||
3.8% Senior Notes due 2024 | 992,036 | 990,964 | ||||||
4.375% Senior Notes due 2028 | 988,061 | — | ||||||
4.9% Senior Notes due 2044 | 691,354 | 691,199 | ||||||
Total debt | 6,353,691 | 6,579,916 | ||||||
Less: Current portion of long-term debt | 2,286 | 2,219 | ||||||
Long-term debt, net of current portion | $ | 6,351,405 | $ | 6,577,697 |
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Credit facility |
| $ | 1,160,000 |
|
| $ | 500,000 |
|
Term loan |
|
| 747,073 |
|
|
| — |
|
Notes payable |
|
| 20,041 |
|
|
| 22,356 |
|
4.5% Senior Notes due 2023 (1) |
|
| 635,648 |
|
|
| 648,078 |
|
3.8% Senior Notes due 2024 |
|
| 891,404 |
|
|
| 908,061 |
|
2.268% Senior Notes due 2026 |
|
| 794,062 |
|
|
| 792,621 |
|
4.375% Senior Notes due 2028 |
|
| 993,076 |
|
|
| 991,880 |
|
5.75% Senior Notes due 2031 |
|
| 1,483,843 |
|
|
| 1,482,319 |
|
2.875% Senior Notes due 2032 |
|
| 792,238 |
|
|
| 791,521 |
|
4.9% Senior Notes due 2044 |
|
| 692,255 |
|
|
| 692,056 |
|
Total debt |
|
| 8,209,640 |
|
|
| 6,828,892 |
|
Less: Current portion of long-term debt |
|
| 638,058 |
|
|
| 2,326 |
|
Long-term debt, net of current portion |
| $ | 7,571,582 |
|
| $ | 6,826,566 |
|
(1) The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.75 billionCompany's 2023 Notes, which have a face value of $636.0 million at December 31, 2017.
Credit Facility
On August 24, 2022, the Company amended its credit facility to increase the amount of aggregate commitments by $255 million from $2.0 billion to $2.255 billion and to replace LIBOR as a benchmark reference rate with Term SOFR, with all other terms, conditions, and covenants remaining substantially unchanged. The Company’s credit facility, which matures in October 2026, is unsecured and has no borrowing base requirement subject to redetermination.
The Company had $1.16 billion of outstanding borrowings on its credit facility at December 31, 2022, which were incurred to fund a portion of the Hamm Family's November 2022 take-private transaction.Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company’s senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at December 31, 20172022 was 3.19%5.9%.
The Company had approximately $2.56$1.09 billion of borrowing availability on its revolving credit facility at December 31, 20172022 after considering outstanding borrowings and letters of credit. The Company incurs commitment fees based on currently assigned credit ratings of 0.30%0.20% per annum on the daily average amount of unused borrowing availability under its revolving credit facility.
The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at December 31, 2017.
Senior Notes due 2028 and received total net proceeds of $990 million after deducting the initial purchasers' fees. The 2028 Notes were sold at par in a private placement transaction exempt from the registration requirements of the Securities Act to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The Company used the net proceeds from the offering to repay in full and terminate its $500 million term loan and to repay a portion of the borrowings outstanding under its revolving credit facility.
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2017.
|
| 2023 Notes |
|
| 2024 Notes |
|
| 2026 Notes |
|
| 2028 Notes |
|
| 2031 Notes |
|
| 2032 Notes |
|
| 2044 Notes |
| |||||||
Face value (in thousands) |
| $ | 636,000 |
|
| $ | 893,126 |
|
| $ | 800,000 |
|
| $ | 1,000,000 |
|
| $ | 1,500,000 |
|
| $ | 800,000 |
|
| $ | 700,000 |
|
Maturity date |
| April 15, 2023 |
|
| June 1, 2024 |
|
| November 15, 2026 |
|
| January 15, 2028 |
|
| January 15, 2031 |
|
| April 1, 2032 |
|
| June 1, 2044 |
| |||||||
Interest payment dates |
| April 15, Oct 15 |
|
| June 1, Dec 1 |
|
| May 15, Nov 15 |
|
| Jan 15, July 15 |
|
| Jan 15, Jul 15 |
|
| April 1, Oct 1 |
|
| June 1, Dec 1 |
| |||||||
Make-whole redemption period (1) |
| Jan 15, 2023 |
|
| Mar 1, 2024 |
|
| Nov 15, 2023 |
|
| Oct 15, 2027 |
|
| Jul 15, 2030 |
|
| January 1. 2032 |
|
| Dec 1, 2043 |
|
68
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
2022 Notes (1) | 2023 Notes | 2024 Notes | 2028 Notes | 2044 Notes | ||||||
Face value (in thousands) | $2,000,000 | $1,500,000 | $1,000,000 | $1,000,000 | $700,000 | |||||
Maturity date | Sep 15, 2022 | April 15, 2023 | June 1, 2024 | January 15, 2028 | June 1, 2044 | |||||
Interest payment dates | March 15, Sep 15 | April 15, Oct 15 | June 1, Dec 1 | Jan 15, July 15 | June 1, Dec 1 | |||||
Make-whole redemption period (2) | — | Jan 15, 2023 | Mar 1, 2024 | Oct 15, 2027 | Dec 1, 2043 |
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. The senior noteThese covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2017. Three2022.
The senior notes are obligations of Continental Resources, Inc. Additionally, certain of the Company’s wholly-owned consolidated subsidiaries Banner(Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations,SCS1 Holdings LLC, Continental Innovations LLC, Jagged Peak Energy LLC, and Parsley SoDe Water LLC) fully and unconditionally guarantee the senior notes on a joint and several basis. The financial information of the guarantor group is not materially different from the consolidated financial statements of the Company. The Company’s other subsidiaries, the value of whose assets, equity, and results of operations attributable to the Company are minor,not material, do not guarantee the senior notes.
Issuance of Senior Notes
2021
In November 2016,2021, the Company redeemed its then outstanding 7.375%issued $800 million of 2.268% Senior Notes due 2020 (“2020 Notes”)2026 and 7.125%$800 million of 2.875% Senior Notes due 2032 and received combined total net proceeds from the offerings of $1.59 billion after deducting the initial purchasers' fees and original issuance discount. The Company used the net proceeds from the offerings to finance a portion of its December 2021 (“2021 Notes”).acquisition of properties in the Permian Basin as discussed in Note 2. Property Acquisitions.
2020
In November 2020, the Company issued $1.5 billion of 5.75% Senior Notes due 2031 and received total net proceeds of $1.49 billion after deducting the initial purchasers' fees. The redemption price forCompany used the net proceeds from the offering to finance the partial repurchases of its 2022 Notes and 2023 Notes in November 2020 Notes was equalas further discussed below, to 102.458%repay a portion of the $200borrowings then-outstanding on its credit facility, and for general corporate purposes.
Retirement of Senior Notes
2022
In the second quarter of 2022, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions, including $13.6 million principal amount plusface value of its 2023 Notes at an aggregate cost of $13.9 million and $17.9 million face value of its 2024 Notes at an aggregate cost of $18.3 million, in each case, including accrued and unpaid interest to the redemption date in accordance with the terms of the 2020 Notes and related indenture. The redemption price for the 2021 Notes was equal to 103.563% of the $400 million principal amount plus accrued and unpaid interest to the redemption date in accordance with the terms of the 2021 Notes and related indenture. The aggregate of the principal amounts, redemption premiums, and accrued interest paid upon redemption of the 2020 Notes and 2021 Notes was $623.9 million. The Company funded the redemptions using borrowings under its revolving credit facility.
2021
In January 2021, the year ended December 31, 2016.
2020
In March and April 2020, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions at a substantial discount to the face value of the notes, including $50.4 million face value of its 2023 Notes at an aggregate cost of $29.3 million and $89.0 million face value of its 2024 Notes at an aggregate cost of $46.9 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax gains on extinguishment of debt totaling $64.6 million related to the repurchases.
69
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
In November 2015,2020, the Company repurchased $469.2 million of its 2022 Notes and $800.0 million of its 2023 Notes using proceeds from its November 2020 issuance of $1.5 billion of 5.75% Senior Notes due 2031. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2022 Notes and 2023 Notes was $475.0 million and $828.0 million, respectively. The Company recorded pre-tax losses on extinguishment of debt totaling $28.9 million related to these repurchases.
Term Loan
In November 2022, the Company borrowed $500$750 million under a three-year term loan agreement, the proceeds of which was scheduledwere used to mature on November 4, 2018. In December 2017, the Company repaid in full and terminated the term loan usingfund a portion of the proceeds from its issuanceHamm Family’s November 2022 take-private transaction. The term loan matures in November 2025 and bears interest at market-based interest rates plus a margin based on the terms of 2028 Notes as described above.the borrowing and the credit ratings assigned to the Company’s senior, unsecured, long-term indebtedness. The interest rate on the term loan was 6.1% at December 31, 2022.
The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0, consistent with the covenant requirement in the Company’s revolving credit facility. The Company recognized a pre-tax loss on extinguishment of $0.6 million related to the termination, representing the write-off of deferred financing costs associatedwas in compliance with the term loan.
Notes Payable
In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary ofJune 2020, the Company borrowed $22an aggregate of $26.0 million under a 10-yeartwo 10-year amortizing term loanloans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The loan bearsloans mature in May 2030 and bear interest at a fixed rate of 3.14%3.50% per annum.annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.3and, accordingly, $2.4 million is reflectedincluded as a current liability underin the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2017.2022 associated with the loans.
Note 9. Revenues
Below is a discussion of the nature, timing, and presentation of revenues arising from the Company’s major revenue-generating arrangements.
Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company’s customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses, as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company’s operated crude oil production totaled $254.0 million, $185.1 million, and $159.0 million for the years ended December 31, 2022, 2021, and 2020, respectively.
Operated natural gas revenues – The Company sells a substantial majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream inclusive of natural gas liquids (“NGLs”) at the lease location and the Company’s revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and NGLs at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas and NGL sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.
Under certain arrangements, the Company may elect to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated production. When the Company elects to take volumes in kind, it takes possession of the processed products at the tailgate of the processing facility and either sells them at the tailgate or pays third parties to transport the products to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled
70
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
to U.S. corporate tax laws thatreceive. Operated sales proceeds are expected to impactgenerally received by the Company includingwithin one month after the month in which a reductionsale has occurred. In these scenarios, the Company’s revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $62.4 million, $39.9 million, and $37.7 million for the years ended December 31, 2022, 2021, and 2020, respectively.
Non-operated crude oil, natural gas, and NGL revenues – The Company’s proportionate share of production from non-operated properties is generally marketed at the discretion of the corporate income tax rateoperators. For non-operated properties, the Company receives a net payment from 35%the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to 21%, effective January 1, 2018. The new legislation also includes a variety of other changes such asbe received by the repealCompany during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs.
Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the alternative minimum tax,Company’s accounting for its derivative instruments.
Revenues from service operations – Revenues from the introductionCompany’s crude oil and natural gas service operations consist primarily of new limitationsrevenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.
Disaggregation of revenues
The following table presents the disaggregation of the Company’s crude oil and natural gas revenues for the periods presented. Sales of natural gas and NGLs are combined, as a substantial majority of the Company’s natural gas sales contracts represent wellhead sales of unprocessed gas.
|
| Year ended December 31, |
| |||||||||||||||||||||||||||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||||||||||||||||||||||||||
In thousands |
| Crude Oil |
|
| Natural Gas and NGLs |
|
| Total |
|
| Crude Oil |
|
| Natural Gas and NGLs |
|
| Total |
|
| Crude Oil |
|
| Natural Gas and NGLs |
|
| Total |
| |||||||||
Bakken |
| $ | 3,899,749 |
|
| $ | 1,051,870 |
|
| $ | 4,951,619 |
|
| $ | 2,786,320 |
|
| $ | 562,695 |
|
| $ | 3,349,015 |
|
| $ | 1,523,348 |
|
| $ | 28,858 |
|
| $ | 1,552,206 |
|
Anadarko Basin |
|
| 1,109,405 |
|
|
| 1,839,473 |
|
|
| 2,948,878 |
|
|
| 874,752 |
|
|
| 1,264,069 |
|
|
| 2,138,821 |
|
|
| 572,653 |
|
|
| 326,626 |
|
|
| 899,279 |
|
Powder River Basin |
|
| 557,943 |
|
|
| 125,065 |
|
|
| 683,008 |
|
|
| 101,705 |
|
|
| 13,110 |
|
|
| 114,815 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Permian Basin |
|
| 1,122,290 |
|
|
| 151,217 |
|
|
| 1,273,507 |
|
|
| 24,857 |
|
|
| 4,499 |
|
|
| 29,356 |
|
|
| — |
|
|
| — |
|
|
| — |
|
All other |
|
| 216,616 |
|
|
| 1,047 |
|
|
| 217,663 |
|
|
| 161,660 |
|
|
| 74 |
|
|
| 161,734 |
|
|
| 103,975 |
|
|
| (26 | ) |
|
| 103,949 |
|
Crude oil, natural gas, and natural gas liquids sales |
| $ | 6,906,003 |
|
| $ | 3,168,672 |
|
| $ | 10,074,675 |
|
| $ | 3,949,294 |
|
| $ | 1,844,447 |
|
| $ | 5,793,741 |
|
| $ | 2,199,976 |
|
| $ | 355,458 |
|
| $ | 2,555,434 |
|
Performance obligations
The Company satisfies the performance obligations under its commodity sales contracts upon delivery of its production and related transfer of control to customers. Judgment may be required in determining the point in time when control transfers to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts determined by the sales contracts.
The Company's outstanding crude oil sales contracts at December 31, 2022 are primarily short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.
The substantial majority of the Company's operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s
71
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
commodity sales contracts, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable.
Contract balances
Under the Company’s commodity sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company’s unconditional rights to receive consideration are presented as a receivable within “Receivables–Crude oil, natural gas, and natural gas liquids sales” or “Receivables–Joint interest and other,” as applicable, in its consolidated balance sheets.
Revenues from previously satisfied performance obligations
To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption “Crude oil, natural gas, and natural gas liquids sales”. Revenues recognized during the years ended December 31, 2022, 2021, and 2020 related to performance obligations satisfied in prior reporting periods were not material.
Note 10. Allowance for Credit Losses
The Company’s principal exposure to credit risk is through the sale of its crude oil, natural gas, and NGL production and its receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the tax deductibilityconsolidated balance sheets as “Receivables—Crude oil, natural gas, and natural gas liquids sales” and “Receivables—Joint interest and other.”
Historically, the Company’s credit losses on receivables have been immaterial. The Company’s aggregate allowance for credit losses totaled $5.5 million and $2.8 million at December 31, 2022 and 2021, respectively, which is reported as “Allowance for credit losses” in the consolidated balance sheets. Aggregate credit loss expenses totaled $3.3 million, $0.8 million, and $1.8 million for the years ended December 31, 2022, 2021, and 2020, respectively, which are included in “General and administrative expenses” in the consolidated statements of net operatingincome (loss).
Receivables—Crude oil, natural gas, and natural gas liquids sales
The Company’s crude oil, natural gas, and NGL production from operated properties is generally sold to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies. The Company monitors its credit loss exposure to these counterparties primarily by reviewing credit ratings, financial statements, and payment history. Credit terms are extended based on an evaluation of each counterparty’s credit worthiness. The Company has not generally required its counterparties to provide collateral to secure its crude oil, natural gas, and NGL sales receivables.
Receivables associated with crude oil, natural gas, and NGL sales are short term in nature. Receivables from the sale of crude oil, natural gas, and NGLs from operated properties are generally collected within one month after the month in which a sale has occurred, while receivables associated with non-operated properties are generally collected within two to three months after the month in which production occurs.
The Company’s allowance for credit losses interest expenses,on crude oil, natural gas, and executive compensation expenses,NGL sales was negligible at both December 31, 2022 and December 31, 2021. The allowance was determined by considering a number of factors, primarily including the accelerationCompany’s history of expensingcredit losses with adjustment as needed to reflect current conditions, the length of certain qualified property,time accounts are past due, whether amounts relate to operated properties or non-operated properties, and the introduction of new laws governing taxation of foreign earnings of U.S. entities, among others.
72
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Receivables—Joint interest and other
Joint interest and other receivables primarily arise from billing the individuals and entities who own a partial interest in the tables below. wells we operate. Joint interest receivables are due within 30 days and are considered delinquent after 60 days. In order to minimize our exposure to credit risk with these counterparties we generally request prepayment of drilling costs where it is allowed by contract or state law. Such prepayments are used to offset future capital costs when billed, thereby reducing the Company’s credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the co-owner’s interest.
The Company also reassessed the realizability of its deferred tax assets, taking into consideration how the new tax law impacts future taxable income,Company’s allowance for credit losses on joint interest receivables totaled $5.5 million and has recorded such assets at realizable value$2.8 million at December 31, 2017.2022 and 2021, respectively. The Company's accountingallowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and the co-owner’s ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the effects of the tax rate change on its deferred tax balances as well as other relevant aspects of the Tax Reform Act is completeyears ended December 31, 2022, 2021, and no provisional amounts have been recorded as allowed under SAB 118.2020.
Note 11. Income Taxes
The items comprising the Company's benefitCompany’s provision (benefit) for income taxes are as follows for the periods presented:
|
| Year ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Current income tax provision (benefit): |
|
|
|
|
|
|
|
|
| |||
United States federal |
| $ | 538,704 |
|
| $ | — |
|
| $ | (2,248 | ) |
Various states |
|
| 83,671 |
|
|
| — |
|
|
| 29 |
|
Total current income tax provision (benefit) |
|
| 622,375 |
|
|
| — |
|
|
| (2,219 | ) |
Deferred income tax provision (benefit): |
|
|
|
|
|
|
|
|
| |||
United States federal |
|
| 374,802 |
|
|
| 467,051 |
|
|
| (148,828 | ) |
Various states |
|
| 23,627 |
|
|
| 52,679 |
|
|
| (18,143 | ) |
Total deferred income tax provision (benefit) |
|
| 398,429 |
|
|
| 519,730 |
|
|
| (166,971 | ) |
Provision (benefit) for income taxes |
| $ | 1,020,804 |
|
| $ | 519,730 |
|
| $ | (169,190 | ) |
Effective tax rate |
|
| 20.1 | % |
|
| 23.8 | % |
|
| 21.8 | % |
Year ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Current income tax (provision) benefit: | ||||||||||||
United States federal (1) | $ | 7,781 | $ | 22,941 | $ | — | ||||||
Various states | — | (2 | ) | (24 | ) | |||||||
Total current income tax (provision) benefit | 7,781 | 22,939 | (24 | ) | ||||||||
Deferred income tax (provision) benefit: | ||||||||||||
United States federal - taxation on operations | (81,054 | ) | 182,422 | 140,578 | ||||||||
United States federal - effect of US tax reform | 713,655 | — | — | |||||||||
Various states | (7,002 | ) | 27,414 | 40,863 | ||||||||
Total deferred income tax benefit | 625,599 | 209,836 | 181,441 | |||||||||
Benefit for income taxes | $ | 633,380 | $ | 232,775 | $ | 181,417 |
The currentCompany’s effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, equity compensation, tax credits, changes in valuation allowances, and other tax items as reflected in the table below.
|
| Year ended December 31, |
| |||||||||
In thousands, except tax rates |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Income (loss) before income taxes |
| $ | 5,068,413 |
|
| $ | 2,186,138 |
|
| $ | (774,751 | ) |
U.S. federal statutory tax rate |
|
| 21.0 | % |
|
| 21.0 | % |
|
| 21.0 | % |
Expected income tax provision (benefit) based on U.S. federal statutory tax rate |
|
| 1,064,367 |
|
|
| 459,089 |
|
|
| (162,698 | ) |
Items impacting the effective tax rate: |
|
|
|
|
|
|
|
|
| |||
State and local income taxes, net of federal benefit |
|
| 126,932 |
|
|
| 77,979 |
|
|
| (24,808 | ) |
Tax (benefit) deficiency from stock-based compensation |
|
| (5,282 | ) |
|
| 5,869 |
|
|
| 4,927 |
|
Change in valuation allowance |
|
| — |
|
|
| (14,474 | ) |
|
| 14,474 |
|
Federal tax credit for increasing research activities (1) |
|
| (151,913 | ) |
|
| — |
|
|
| — |
|
Other, net |
|
| (13,300 | ) |
|
| (8,733 | ) |
|
| (1,085 | ) |
Provision (benefit) for income taxes |
| $ | 1,020,804 |
|
| $ | 519,730 |
|
| $ | (169,190 | ) |
Effective tax rate |
|
| 20.1 | % |
|
| 23.8 | % |
|
| 21.8 | % |
In assessing the realizability of deferred tax assets the Company must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company applies judgment to determine the weight of both positive and 2016 represent alternative minimum tax refunds.
73
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
negative evidence in order to conclude whether a valuation allowance is necessary for its deferred tax assets. In determining whether a valuation allowance is required, the Company considers, among other factors, the Company’s financial position, results of operations, projected future taxable income, taxes differs from the amount computed by applying the United States statutory federal incomereversal of existing deferred tax rate to income (loss) before income taxes. The sourcesliabilities against deferred tax assets, and tax effectsplanning strategies. During 2020, a $14.5 million valuation allowance was established for the deferred tax asset associated with a portion of the difference are as follows:
The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to its deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of our deferred tax assets that could have a material impact on our consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time.
Year ended December 31, | |||||||||||||||||||||
2017 | 2016 | 2015 | |||||||||||||||||||
In thousands, except rates | Amount | Rate | Amount | Rate | Amount | Rate | |||||||||||||||
Expected income tax (provision) benefit based on US statutory tax rate of 35% | $ | (54,623 | ) | 35.0 | % | $ | 221,359 | 35.0 | % | $ | 187,280 | 35.0 | % | ||||||||
State income taxes, net of federal benefit | (4,682 | ) | 3.0 | % | 18,829 | 3.0 | % | 16,219 | 3.0 | % | |||||||||||
Effect of US tax reform legislation | 713,655 | (457.3 | %) | — | — | % | — | — | % | ||||||||||||
Tax deficiency from stock-based compensation (1) | (3,932 | ) | 2.5 | % | — | — | % | — | — | % | |||||||||||
Canadian valuation allowance (2) | (404 | ) | 0.3 | % | (1,044 | ) | (0.2 | %) | (13,503 | ) | (2.5 | %) | |||||||||
Effect of differing statutory tax rate in Canada | (194 | ) | 0.1 | % | (481 | ) | (0.1 | %) | (5,239 | ) | (1.0 | %) | |||||||||
Non-deductible compensation | (13,813 | ) | 8.9 | % | (3,471 | ) | (0.5 | %) | (1,488 | ) | (0.3 | %) | |||||||||
Other, net | (2,627 | ) | 1.7 | % | (2,417 | ) | (0.4 | %) | (1,852 | ) | (0.3 | %) | |||||||||
Benefit for income taxes | $ | 633,380 | (405.8 | %) | $ | 232,775 | 36.8 | % | $ | 181,417 | 33.9 | % |
The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 20172022 and 20162021 are reflected in the table below.
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Deferred tax assets |
|
|
|
|
|
| ||
United States net operating loss carryforwards |
| $ | 63,128 |
|
| $ | 365,602 |
|
Incentive/equity compensation |
|
| 34,987 |
|
|
| 12,751 |
|
Net deferred hedge losses |
|
| 42,898 |
|
|
| — |
|
Other |
|
| 31,324 |
|
|
| 29,421 |
|
Total deferred tax assets |
|
| 172,337 |
|
|
| 407,774 |
|
Valuation allowance |
|
| — |
|
|
| — |
|
Total deferred tax assets, net of valuation allowance |
|
| 172,337 |
|
|
| 407,774 |
|
Deferred tax liabilities |
|
|
|
|
|
| ||
Property and equipment |
|
| (2,708,641 | ) |
|
| (2,536,938 | ) |
Other |
|
| (2,008 | ) |
|
| (10,720 | ) |
Total deferred tax liabilities |
|
| (2,710,649 | ) |
|
| (2,547,658 | ) |
Deferred income tax liabilities, net |
| $ | (2,538,312 | ) |
| $ | (2,139,884 | ) |
December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Deferred tax assets | ||||||||
United States net operating loss carryforwards | $ | 604,423 | $ | 478,975 | ||||
Canadian net operating loss carryforwards | 19,341 | 18,936 | ||||||
Alternative minimum tax carryforwards | 7,781 | 16,663 | ||||||
Equity compensation | 12,962 | 32,924 | ||||||
Non-cash losses on derivatives | — | 21,064 | ||||||
Other | 21,885 | 11,466 | ||||||
Total deferred tax assets | 666,392 | 580,028 | ||||||
Canadian valuation allowance | (19,341 | ) | (18,936 | ) | ||||
Total deferred tax assets, net of valuation allowance | 647,051 | 561,092 | ||||||
Deferred tax liabilities | ||||||||
Property and equipment | (1,903,451 | ) | (2,448,450 | ) | ||||
Other | (3,158 | ) | (2,947 | ) | ||||
Total deferred tax liabilities | (1,906,609 | ) | (2,451,397 | ) | ||||
Deferred income tax liabilities, net | $ | (1,259,558 | ) | $ | (1,890,305 | ) |
As of December 31, 2017,2022, the Company had federal and state net operating loss (“NOL”) carryforwards of $2.39 billion and $3.40 billion, respectively. The federal net operating loss carryforward will begin expiring in 2033. The Company’s net operating loss carryforward in Oklahoma totaled $2.17totaling $1.99 billion, of which $881 million expires between 2034 and 2037, and the remaining $1.11 billion has an indefinite life. In 2022, the Company utilized all of its previously generated federal NOL carryforwards to offset a portion of its 2022 federal taxable income and no federal NOL or tax credit carryforwards remain at December 31, 2017, which will begin to expire2022. Additionally, in 2027. The Company’s net operating loss carryforward2022 the Company utilized all of its previously generated NOL carryforwards in North Dakota totaled $1.07 billionto offset a portion of its 2022 taxable income in that state and no North Dakota NOL carryforwards remain at December 31, 2017, which will begin to expire in 2033.
Note 12. Leases
The Company recorded valuation allowances of $0.4 million, $1.0Company’s lease liabilities recognized on the balance sheet as a lessee totaled $24.1 million and $13.5 million against Canadian deferred tax assets for the years ended December 31, 2017, 2016 and 2015, respectively. The Company's cumulative valuation allowance was $19.3$15.5 million as of December 31, 2017. Our Canadian subsidiary has generated operating loss carryforwards for2022 and 2021, respectively, at discounted present value, which we do not believe we will realize a benefit. The amountis comprised of deferred tax assets considered realizable, however, could change if our subsidiary generates taxable income.
The Company accounts for reporting periods beginning after December 15, 2018 that will impactlease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company's accountingCompany does not apply the recognition requirements of ASC Topic 842 to leases with durations of twelve months or less and uses hindsight in determining the lease term for all leases. See Note 1. OrganizationThe Company’s leasing activities as a lessor are negligible.
74
Continental Resources, Inc. and SummarySubsidiaries
Notes to Consolidated Financial Statements
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Surface use agreements |
| $ | 18,136 |
|
| $ | 12,354 |
|
Field equipment |
|
| 5,224 |
|
|
| 2,095 |
|
Other |
|
| 781 |
|
|
| 1,025 |
|
Total |
| $ | 24,141 |
|
| $ | 15,474 |
|
Minimum future commitments by year for the Company’s operating leases as of Significant Accounting Policies–New accounting pronouncements not yet adopted at December 31, 2017–Leases2022 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.
In thousands |
| Amount |
| |
2023 |
| $ | 5,180 |
|
2024 |
|
| 4,172 |
|
2025 |
|
| 1,885 |
|
2026 |
|
| 1,848 |
|
2027 |
|
| 1,827 |
|
Thereafter |
|
| 18,351 |
|
Total operating lease liabilities, at undiscounted value |
| $ | 33,263 |
|
Less: Imputed interest |
|
| (9,122 | ) |
Total operating lease liabilities, at discounted present value |
| $ | 24,141 |
|
Less: Current portion of operating lease liabilities |
|
| (4,086 | ) |
Operating lease liabilities, net of current portion |
| $ | 20,055 |
|
Additional information for further discussion.
|
| Year ended December 31, |
| |||||||||
In thousands, except weighted average data |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Lease costs: |
|
|
|
|
|
|
|
|
| |||
Operating lease costs |
| $ | 3,484 |
|
| $ | 6,653 |
|
| $ | 6,444 |
|
Variable lease costs |
|
| 650 |
|
|
| 3,271 |
|
|
| 4,956 |
|
Short-term lease costs |
|
| 124,535 |
|
|
| 77,551 |
|
|
| 107,984 |
|
Total lease costs |
| $ | 128,669 |
|
| $ | 87,475 |
|
| $ | 119,384 |
|
|
|
|
|
|
|
|
|
|
| |||
Other information: |
|
|
|
|
|
|
|
|
| |||
Right-of-use assets obtained in exchange for new operating lease liabilities |
| $ | 19,944 |
|
| $ | 10,481 |
|
| $ | 7,377 |
|
Operating cash flows from operating leases included in lease liabilities |
|
| 4,370 |
|
|
| 1,731 |
|
|
| 890 |
|
Weighted average remaining lease term as of December 31 (in years) |
|
| 12.0 |
|
|
| 14.4 |
|
|
| 13.2 |
|
Weighted average discount rate as of December 31 |
|
| 4.8 | % |
|
| 5.0 | % |
|
| 4.8 | % |
In thousands | Total amount | |||
2018 | $ | 1,656 | ||
2019 | 958 | |||
2020 | 817 | |||
2021 | 645 | |||
2022 | 620 | |||
Thereafter | 7,208 | |||
Total obligations | $ | 11,904 |
Note 10.13. Commitments and Contingencies
Transportation, gathering, and processing commitments –
The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as75
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Lease commitments – The Company has various lease commitments primarily associated with surface use agreements and remanded the casefield equipment. See Note 12. Leases for further proceedings. The plaintiffs filedadditional information.
Strategic investment – See Note 18. Equity Investment for discussion of future spending commitments associated with a Petition for Rehearing which was deniedstrategic investment announced by the Oklahoma CourtCompany in the first quarter of Civil Appeals. Plaintiffs then filed a Petition for Writ of Certiorari on May 23, 20172022.
Litigation pertaining to the Oklahoma Supreme Court, which was denied on October 2, 2017. On October 10, 2017, Plaintiffs filed with the trial court a “Second Amended and Renewed Motion for Class Action Certification and Request that the Court to Set a Briefing Schedule Related to Class Certification.” During the litigationCompany's routine operations
In March 2022, the Company was not able to estimatenamed as a reasonably possible loss or rangedefendant in a case filed in the U.S. District Court for the Northern District of loss or what impact, if any,California by gasoline consumer plaintiffs alleging that, beginning in March 2020, the ultimate resolution of the action would have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existenceCompany and the potential sizeother named defendants conspired with Russia, OPEC and others to raise the price of oil and gasoline by reducing the class, the scopesupply of these products. The plaintiffs are seeking unspecified damages and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The Company further disclosed that it was reasonably possible one or more events could occur in the near term that could impact the Company’s ability to estimate the potential effect of this matter if any, on its financial condition, results of operations or cash flows. During the litigationinjunctive relief. On July 1, 2022, the Company, also disclosed plaintiffs alleged underpayments in excess of $200 million as damages, which may increasetogether with the passage of time, a majority of which would be comprised of interest. After certification of the case as a class action was reversed the parties continued settlement negotiations. Dueother named defendants, filed motions to the uncertainty of and burdens of litigation, on February 16, 2018, the Company reached a settlement in connection with this matter. Under the settlement, if approved bydismiss. On January 9, 2023, the court granted the Company will make payments and incur costs associated with the settlement of approximately $59.6 million. The Company has accrued a loss for such amount, which is included in “Accrued liabilities and other” on the consolidated balance sheets and “Litigation settlement” in the consolidated statements of comprehensive income (loss) as of and for the year ended December 31, 2017. The District Court of Garfield County, Oklahoma must approve the settlement.
The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of December 31, 20172022 and 2016,2021, the Company had recordedrecognized a liability in the consolidated balance sheets under the captionwithin “Other noncurrent liabilities” of $7.6$20.2 million and $6.5$7.9 million, respectively, for various matters, none of which are believed to be individually significant.
Litigation pertaining to take-private transaction
Transactions such as the Hamm Family's take-private transaction described in Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction often attract litigation and demands from minority shareholders.
On August 25, 2022, Walter T. Doggett, on behalf of himself and a class of all other similarly situated shareholders (“Doggett”), filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, as the controlling shareholder of the Company, for alleged breaches of fiduciary duties in connection with the take-private transaction. On November 7, 2022, Doggett filed an amended class action petition adding as additional defendants the Company, certain trusts established for the benefit of Mr. Hamm and/or his family members (the “Hamm Family Trusts”), and the Company’s other directors. Doggett alleges that the defendants breached their fiduciary duties in the connection with the take-private transaction and seeks: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.
On November 23, 2022, Ralph Donald Turlington, Alroc Real Estate Associates (Del.) LLC, and the Turlington Family Irrevocable Trust, on behalf of themselves and a class of all other similarly situated former shareholders (“Turlington”), filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors. Turlington alleges the defendants breached their fiduciary duties in connection with the take-private transaction and seeks: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.
On November 30, 2022, Doggett and Turlington filed a motion to consolidate the Doggett and Turlington lawsuits and to appoint lead and liaison counsel.
On August 11, 2022, Pembroke Pines Firefighters & Police Officers Pension Fund (“Pembroke”), a shareholder, delivered a letter (the “Pembroke Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the Company’s directors and senior management in connection with the take-private transaction. On August 18, 2022, the Company responded to the Pembroke Request. On October 20, 2022, Pembroke updated the Pembroke Request, and the Company again responded to the Pembroke Request on October 27, 2022. The Company has subsequently produced certain information to Pembroke identified in the Pembroke Request. On November 17, 2022, Pembroke filed a verified petition in the District Court of Pottawatomie County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Pembroke Request; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.
On December 6, 2022, Pembroke filed a motion to intervene and stay the Doggett and Turlington lawsuits until Pembroke completes its inspection of the Company’s books and records and prepares its own lawsuit.
On November 2, 2022, Kevin Barry (“Barry”), a shareholder, delivered a letter (the “Barry Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the
76
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Company’s directors and senior management in connection with the take-private transaction. On November 9, 2022, the Company responded to the Barry Request. The Company has subsequently produced certain information to Barry identified in the Barry Request. On November 18, 2022, Barry filed a verified petition in the District Court of Oklahoma County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Barry Request; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.
On November 10, 2022, Kerry Panozzo (“Panozzo”), a shareholder, delivered a letter (the “Panozzo Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the Company’s directors and senior management in connection with the take-private transaction. On November 17, 2022, the Company responded to the Panozzo Request. The Company has subsequently produced certain information to Panozzo identified in the Panozzo Request. On November 21, 2022, Panozzo filed a verified petition in the District Court of Oklahoma County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Panozzo Request; (ii) the costs and expenses associated the lawsuit; and (iii) other equitable relief.
In November 2022, the Company received letters demanding appraisal of their respective shares of the Company’s common stock from FourWorld Deep Value Opportunities Fund I, LLC, FourWorld Event Opportunities, LP, FW Deep Value Opportunities I, LLC, FourWorld Global Opportunities Fund, Ltd., FourWorld Special Opportunities Fund, LLC, Corbin ERISA Opportunity Fund Ltd., and Quadre Investments, L.P. (collectively, “FourWorld”). On January 5, 2023, these parties filed a petition in the District Court of Oklahoma County, Oklahoma, seeking appraisal of their respective shares of the Company’s common stock in connection with the take-private transaction.
On January 13, 2023, the Company, Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors filed a motion to consolidate the Doggett, Turlington, and FourWorld lawsuits. On January 26, 2023, the Company filed a motion to stay the FourWorld appraisal lawsuit pending adjudication of the Company’s motion to consolidate the Doggett, Turlington, and FourWorld lawsuits.
On February 14, 2023, Pembroke and Panozzo, on behalf of themselves and a class of all other similarly situated former shareholders, filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors. Pembroke and Panozzo allege the defendants breached their fiduciary duties in connection with the take-private transaction and seek: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.
The Company, Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors intend to vigorously defend themselves against the foregoing matters.
Environmental risk –
Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.Note 11.14. Related Party Transactions
Certain officers of the Company own or control entities that own working and royalty interests in wells operated by the Company. The Company paid revenues to these affiliates, including royalties, of $0.5$0.5 million, $0.4$0.4 million, and $0.7$0.2 million and received payments from these affiliates of $0.3$0.2 million, $0.3$0.1 million, and $0.5$0.3 million during the years ended December 31, 2017, 2016,2022, 2021, and 2015,2020, respectively, relating to the operations of the respective properties. At December 31, 20172022 and 2016,2021, approximately $58,000$6,000 and $90,000$39,000, respectively, was due from these affiliates respectively,relating to these transactions, which is included in “Receivables—Joint interest and other” on the consolidated balance sheets. At December 31, 2022 and 2021, approximately $48,000$36,000 and $45,000$37,000, respectively, was due to these affiliates respectively, relating to these transactions.
The Company allows certain affiliates to use its corporate aircraft and crews and has used the aircraft of those same affiliates from time to time in order to facilitate efficient transportation of Company personnel. The rates charged between the parties vary by type of aircraft used. In 2016, the Company also purchased an existing prepaid maintenance account from an affiliate for use in major engine overhaul to be applied as needed for corporate aircrafts. For usage during 2017, 2016,2022, 2021, and 2015,2020, the
77
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 20172022 and 2016,2021, approximately $4,200$9,800 and $3,400$6,300, respectively, was due from an affiliate respectively,relating to these transactions, which is included in “Receivables—Joint interest and other” on the consolidated balance sheets. At December 31, 2022 and 2021, approximately $92,000$49,000 and $97,000$33,000, respectively, was due to an affiliate respectively, relating to these transactions.transactions, which is included in “Accounts payable trade” on the consolidated balance sheets.
Note 12.15. Stock-Based Compensation
Prior to the Company adopted ASU 2016-09,
As of the Company adoptedNovember 22, 2022 effective time of the Hamm Family’s take-private transaction, each unvested restricted stock award previously issued under the Company’s 2013 Plan and reserved 19,680,072 shares2022 Plan that was outstanding immediately prior to the effective time was replaced with a restricted stock unit award (the “Rollover Shares”) issued by the Company that provides the holder of commonsuch previous award with the right to receive, on the date that such restricted stock that may be issuedaward otherwise would have been settled, and at the Company’s sole discretion, either a share of the Company, a cash award designed to provide substantially equivalent value, or any combination of the two. Upon this event, the Company remeasured the cumulative compensation expense recognized on the modified awards pursuant to ASC Topic 718, Compensation—Stock Compensation, which resulted in the plan. recognition of additional non-cash compensation expense within “General and administrative expenses” totaling approximately $136 million, reflecting the increase in the value of the awards from the original grant date to the subsequent modification date.
As of December 31, 2017,2022, the Company had 14,538,540 shares5.3 million Rollover Shares, of common stock available for long-termwhich the Company currently intends to settle all awards vesting in 2023, 2024, and 2025 in cash. Thus, the Rollover Shares are classified as a liability award under ASC 718 and, as of December 31, 2022, the Company had recorded a current liability of $125.7 million and a non-current liability of $100.1 million in the captions “Current portion of incentive awardscompensation liability” and “Incentive compensation liability, net of current portion,” respectively, in the consolidated balance sheets. Such amounts reflect the Company’s estimate of expected future cash payments multiplied by the percentage of requisite service periods that employees have completed as of December 31, 2022. The Company’s liability will be remeasured each reporting period to reflect additional services rendered by employees and directors under the 2013 Plan.
A summary of changes in non-vested restricted shares from December 31, 20142019 to December 31, 20172022 is presented below.
|
| Number of |
|
| Weighted |
| ||
Non-vested restricted shares at December 31, 2019 |
|
| 3,461,908 |
|
| $ | 46.82 |
|
Granted |
|
| 2,738,625 |
|
|
| 26.93 |
|
Vested |
|
| (1,146,618 | ) |
|
| 45.78 |
|
Forfeited |
|
| (163,277 | ) |
|
| 36.69 |
|
Non-vested restricted shares at December 31, 2020 |
|
| 4,890,638 |
|
| $ | 36.26 |
|
Granted |
|
| 3,050,491 |
|
|
| 24.73 |
|
Vested |
|
| (1,750,483 | ) |
|
| 44.36 |
|
Forfeited |
|
| (296,138 | ) |
|
| 26.61 |
|
Non-vested restricted shares at December 31, 2021 |
|
| 5,894,508 |
|
| $ | 28.38 |
|
Granted |
|
| 1,575,847 |
|
|
| 56.52 |
|
Vested |
|
| (1,736,678 | ) |
|
| 36.04 |
|
Forfeited |
|
| (384,536 | ) |
|
| 27.82 |
|
Canceled shares due to take-private transaction |
|
| (5,349,141 | ) |
|
| 34.22 |
|
Non-vested restricted shares at December 31, 2022 |
|
| — |
|
| $ | — |
|
78
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Number of non-vested shares | Weighted average grant-date fair value | ||||||
Non-vested restricted shares at December 31, 2014 | 2,678,764 | $ | 49.40 | ||||
Granted | 1,462,534 | 46.65 | |||||
Vested | (555,517 | ) | 48.07 | ||||
Forfeited | (336,170 | ) | 51.23 | ||||
Non-vested restricted shares at December 31, 2015 | 3,249,611 | $ | 48.20 | ||||
Granted | 2,064,508 | 22.36 | |||||
Vested | (1,207,235 | ) | 41.27 | ||||
Forfeited | (193,250 | ) | 39.79 | ||||
Non-vested restricted shares at December 31, 2016 | 3,913,634 | $ | 37.12 | ||||
Granted | 1,585,870 | 44.58 | |||||
Vested | (874,665 | ) | 57.36 | ||||
Forfeited | (598,729 | ) | 37.34 | ||||
Non-vested restricted shares at December 31, 2017 | 4,026,110 | $ | 35.63 |
The grant date fair value of restricted stock representsgranted prior to the Hamm Family’s take-private transaction represented the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant iswas determined at the grant date fair value and iswas recognized over the vesting period as services arewere rendered by employees and directors. The Company estimatesestimated the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There arewere no post-vesting restrictions
Note 16. Shareholders’ Equity Attributable to Continental Resources
See the Consolidated Statements of Equity for the year ended December 31, 2017, there was approximately $58 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.2 years.
Share Repurchases
In May 2019 the Company’s Board of translating foreign functional currency financial statements into U.S. dollarsDirectors approved the initiation of a share repurchase program. Share repurchases made under the program prior to the Hamm Family’s take-private transaction are included in “Accumulated other comprehensive income (loss)” within shareholders’ equity on the consolidated balance sheets and “Other comprehensive income (loss), net of tax” in the consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income (loss)reflected below for the years ended December 31, 2017, 2016,2022, 2021, and 2015:2020.
|
| Number of |
|
| Aggregate cost (in thousands) |
| ||
2020 Share Repurchases |
|
| 8,122,104 |
|
| $ | 126,906 |
|
2021 Share Repurchases |
|
| 3,198,571 |
|
|
| 123,924 |
|
2022 Share Repurchases |
|
| 1,842,422 |
|
|
| 99,855 |
|
Total |
|
| 13,163,097 |
|
| $ | 350,685 |
|
Year ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Beginning accumulated other comprehensive loss, net of tax | $ | (260 | ) | $ | (3,354 | ) | $ | (385 | ) | |||
Foreign currency translation adjustments | 567 | 3,094 | (2,969 | ) | ||||||||
Income taxes (1) | — | — | — | |||||||||
Other comprehensive income (loss), net of tax | 567 | 3,094 | (2,969 | ) | ||||||||
Ending accumulated other comprehensive income (loss), net of tax | $ | 307 | $ | (260 | ) | $ | (3,354 | ) |
As discussed in Note 14. Property Dispositions
Dividend Payments
The following table summarizes the dividends paid by the Company on its then-outstanding common stock for the years ended December 31, 2022, 2021, and 2020.
|
| Amount (in thousands) |
|
| Dividend per share |
| ||
Year Ended December 31, 2020 |
|
|
|
|
|
| ||
First quarter |
| $ | 18,367 |
|
| $ | 0.05 |
|
Total |
| $ | 18,367 |
|
|
|
| |
Year Ended December 31, 2021 |
|
|
|
|
|
| ||
Second quarter |
| $ | 39,735 |
|
| $ | 0.11 |
|
Third quarter |
|
| 54,141 |
|
| $ | 0.15 |
|
Fourth quarter |
|
| 71,793 |
|
| $ | 0.20 |
|
Total |
| $ | 165,669 |
|
|
|
| |
Year Ended December 31, 2022 |
|
|
|
|
|
| ||
First quarter |
| $ | 82,529 |
|
| $ | 0.23 |
|
Second quarter |
|
| 100,123 |
|
| $ | 0.28 |
|
Third quarter |
|
| 100,131 |
|
| $ | 0.28 |
|
Total |
| $ | 282,783 |
|
|
|
|
79
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 17. Noncontrolling Interests
Strategic mineral relationship
In October 2018, Continental entered into a strategic relationship with Franco-Nevada Corporation to acquire oil and gas mineral interests within an area of mutual interest through a minerals subsidiary named The Mineral Resources Company II, LLC (“TMRC II”). At closing in October 2018, Continental contributed most of its previously acquired mineral interests to TMRC II in exchange for a 50.1% ownership interest in the Arkoma Woodford areaentity and Franco-Nevada paid $214.8 million to Continental for cash proceedsa 49.9% ownership interest in TMRC II and for funding of $65.3 million.its share of certain mineral acquisition costs. Under the arrangement, Continental funds 20% of mineral acquisitions and will be entitled to receive between 25% and 50% of total revenues generated by TMRC II based upon performance relative to certain predetermined production targets.
Continental holds a controlling financial interest in TMRC II and manages its operations. Accordingly, Continental consolidates the financial results of the entity and presents the portion of TMRC II’s results attributable to Franco-Nevada as a noncontrolling interest in its consolidated financial statements. Periodically, Franco-Nevada makes capital contributions to, and receives revenue distributions from, TMRC II and the portion of Continental’s consolidated net assets attributable to Franco-Nevada totaled $361.4 million and $369.8 million at December 31, 2022 and 2021, respectively.
Joint ownership arrangement
Continental maintains an arrangement with a third party to jointly own parking facilities adjacent to the companies’ corporate office buildings. The sale included approximately 26,000activities of the parking facilities, which are immaterial to Continental, are managed through an entity named SFPG, LLC (“SFPG”). Continental holds a controlling financial interest in SFPG and manages its operations. Accordingly, Continental consolidates the financial results of the entity and includes the results attributable to the third party within noncontrolling interests in Continental’s financial statements. The portion of Continental’s consolidated net acresassets attributable to the third party's ownership interest in SFPG totaled $11.0 million and $11.1 million at December 31, 2022 and 2021, respectively.
Note 18. Equity Investment
In March 2022 the Company began investing in an affiliate of leaseholdSummit Carbon Solutions (“Summit”) to develop carbon capture and sequestration infrastructure. Summit was founded in Atoka, Coal, Hughes, and Pittsburg Counties of Oklahoma and producing properties with production totaling approximately 1,700 barrels of oil equivalent per day. In connection2020 with the transaction,goal of decarbonizing the biofuel and agriculture industries and seeks to lower greenhouse gas emissions by connecting industrial facilities via strategic infrastructure to capture, transport, and store carbon dioxide (“CO2”) safely and permanently in the Midwestern United States.
The Company has committed to invest a total of $250 million with Summit over 2022 and 2023 to fund a portion of Summit’s development and construction of capture, transportation, and sequestration infrastructure, while also leveraging the Company’s operational and geologic expertise to facilitate the underground storage of CO2. Summit intends to primarily capture CO2 from ethanol plants and other industrial sources in Iowa, Nebraska, Minnesota, North Dakota, and South Dakota, and aggregate and transport the CO2 to North Dakota via pipeline, where it will be sequestered in subsurface geologic formations. The project is expected to become operational in 2024.
During the year ended December 31, 2022, the Company recognized a pre-tax losscontributed approximately $210 million toward its $250 million commitment to Summit, which is included in the caption “Investment in unconsolidated affiliates” in the consolidated balance sheet. Upon completion of $3.5 millionSummit’s ongoing equity raises, the Company expects to hold an approximate 22% non-controlling ownership interest in the equity of Summit Carbon Holdings, the parent company of Summit Carbon Solutions. The Company is not the primary beneficiary of Summit and accounts for its investment under the equity method of accounting. The Company’s share of earnings/losses from its investment was immaterial for the year ended December 31, 2017. The disposed properties represented an immaterial portion of the Company’s proved reserves.2022.
80
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 15.19. Crude Oil and Natural Gas Property Information
The tables reflected below represent consolidated figures for the Company and its subsidiaries. In 2014,Results attributable to noncontrolling interests are not material relative to the Company initiated exploratory drilling activities in Canada. Through December 31, 2017, those drilling activities haveCompany's consolidated results and are not had a material impact on the Company’s total capital expenditures, production, and revenues. Accordingly, the results of operations, costs incurred, and capitalized costs associated with the Canadian operations have not been shown separately from the consolidated figures in the tablespresented below.
The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2017, 20162022, 2021, and 2015.
|
| Year ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Crude oil, natural gas, and natural gas liquids sales |
| $ | 10,074,675 |
|
| $ | 5,793,741 |
|
| $ | 2,555,434 |
|
Production expenses |
|
| (621,921 | ) |
|
| (406,906 | ) |
|
| (359,267 | ) |
Production and ad valorem taxes |
|
| (730,132 | ) |
|
| (404,362 | ) |
|
| (192,718 | ) |
Transportation, gathering, processing, and compression |
|
| (316,414 | ) |
|
| (224,989 | ) |
|
| (196,692 | ) |
Exploration expenses |
|
| (23,068 | ) |
|
| (21,047 | ) |
|
| (17,732 | ) |
Depreciation, depletion, amortization and accretion |
|
| (1,856,067 | ) |
|
| (1,872,075 | ) |
|
| (1,859,893 | ) |
Property impairments |
|
| (70,417 | ) |
|
| (38,370 | ) |
|
| (277,941 | ) |
Income tax (provision) benefit (1) |
|
| (1,512,132 | ) |
|
| (690,902 | ) |
|
| 83,427 |
|
Results from crude oil and natural gas producing activities |
| $ | 4,944,524 |
|
| $ | 2,135,090 |
|
| $ | (265,382 | ) |
Year ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Crude oil and natural gas sales | $ | 2,982,966 | $ | 2,026,958 | $ | 2,552,531 | ||||||
Production expenses | (324,214 | ) | (289,289 | ) | (348,897 | ) | ||||||
Production taxes | (208,278 | ) | (142,388 | ) | (200,637 | ) | ||||||
Exploration expenses | (12,393 | ) | (16,972 | ) | (19,413 | ) | ||||||
Depreciation, depletion, amortization and accretion | (1,652,180 | ) | (1,679,485 | ) | (1,722,336 | ) | ||||||
Property impairments | (237,370 | ) | (237,292 | ) | (402,131 | ) | ||||||
Income tax benefit (1) | 504,475 | 126,794 | 33,680 | |||||||||
Results from crude oil and natural gas producing activities | $ | 1,053,006 | $ | (211,674 | ) | $ | (107,203 | ) |
Costs incurred in crude oil and natural gas activities
Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2017, 20162022, 2021 and 20152020 are presented below:
|
| Year ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Property acquisition costs: |
|
|
|
|
|
|
|
|
| |||
Proved |
| $ | 458,762 |
|
| $ | 2,580,271 |
|
| $ | 60,494 |
|
Unproved |
|
| 412,571 |
|
|
| 1,197,507 |
|
|
| 201,919 |
|
Total property acquisition costs |
|
| 871,333 |
|
|
| 3,777,778 |
|
|
| 262,413 |
|
Exploration Costs |
|
| 343,117 |
|
|
| 171,549 |
|
|
| 48,282 |
|
Development Costs |
|
| 2,185,645 |
|
|
| 1,174,828 |
|
|
| 1,053,532 |
|
Total |
| $ | 3,400,095 |
|
| $ | 5,124,155 |
|
| $ | 1,364,227 |
|
Year ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Property acquisition costs: | ||||||||||||
Proved | $ | 8,446 | $ | 5,008 | $ | 557 | ||||||
Unproved | 220,875 | 149,962 | 168,492 | |||||||||
Total property acquisition costs | 229,321 | 154,970 | 169,049 | |||||||||
Exploration Costs | 123,461 | 182,355 | 241,523 | |||||||||
Development Costs | 1,695,954 | 767,148 | 2,148,530 | |||||||||
Total | $ | 2,048,736 | $ | 1,104,473 | $ | 2,559,102 |
Costs incurred above include asset retirement costs and revisions thereto of $15.3$30.8 million, ($9.6)$31.1 million and $22.8$18.1 million for the years ended December 31, 2017, 20162022, 2021 and 2015,2020, respectively.
Aggregate capitalized costs
Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 20172022 and 20162021 are as follows:
|
| December 31, |
| |||||
In thousands |
| 2022 |
|
| 2021 |
| ||
Proved crude oil and natural gas properties |
| $ | 34,741,054 |
|
| $ | 31,613,656 |
|
Unproved crude oil and natural gas properties |
|
| 1,513,627 |
|
|
| 1,358,673 |
|
Total |
|
| 36,254,681 |
|
|
| 32,972,329 |
|
Less accumulated depreciation, depletion and amortization |
|
| (18,134,473 | ) |
|
| (16,310,054 | ) |
Net capitalized costs |
| $ | 18,120,208 |
|
| $ | 16,662,275 |
|
December 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Proved crude oil and natural gas properties | $ | 21,362,199 | $ | 19,802,395 | ||||
Unproved crude oil and natural gas properties | 365,413 | 429,562 | ||||||
Total | 21,727,612 | 20,231,957 | ||||||
Less accumulated depreciation, depletion and amortization | (8,971,935 | ) | (7,553,255 | ) | ||||
Net capitalized costs | $ | 12,755,677 | $ | 12,678,702 |
Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling and completion operations are complete, management
81
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of comprehensive income (loss) as dry hole costs, a component of “Exploration expenses”.expenses.” Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities.
On at least a quarterly basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period of determination.
The following table presents the amount of capitalized exploratory drillingwell costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended:
|
| Year ended December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Balance at January 1 |
| $ | 37,673 |
|
| $ | 32,737 |
|
| $ | 6,257 |
|
Additions to capitalized exploratory well costs pending determination of proved reserves |
|
| 286,059 |
|
|
| 122,068 |
|
|
| 32,880 |
|
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves |
|
| (229,348 | ) |
|
| (117,131 | ) |
|
| (72 | ) |
Capitalized exploratory well costs charged to expense |
|
| (9,562 | ) |
|
| (1 | ) |
|
| (6,328 | ) |
Balance at December 31 |
| $ | 84,822 |
|
| $ | 37,673 |
|
| $ | 32,737 |
|
Number of gross wells |
|
| 36 |
|
|
| 17 |
|
|
| 16 |
|
Year ended December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Balance at January 1 | $ | 34,852 | $ | 59,397 | $ | 93,421 | ||||||
Additions to capitalized exploratory well costs pending determination of proved reserves | 79,451 | 123,980 | 132,806 | |||||||||
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | (81,035 | ) | (141,941 | ) | (160,779 | ) | ||||||
Capitalized exploratory well costs charged to expense | (1,912 | ) | (6,584 | ) | (6,051 | ) | ||||||
Balance at December 31 | $ | 31,356 | $ | 34,852 | $ | 59,397 | ||||||
Number of gross wells | 37 | 54 | 73 |
As of December 31, 2017,2022, the Company had no significant exploratory drillingwell costs that were suspended one year beyond the completion of drilling.
Note 16.20. Supplemental Crude Oil and Natural Gas Information (Unaudited)
The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. prepared reserve estimates for properties comprising approximately 96%98%, 99%98%, and 98%95% of the Company'sCompany’s total proved reserves as of December 31, 2017, 2016,2022, 2021, and 2015,2020, respectively. Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. No provedProved reserves have been included forattributable to noncontrolling interests are not material relative to the Company’s Canadian operations as of December 31, 2017, 2016,Company's consolidated reserves and 2015.
Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate
Reserves at December 31, 2017, 20162022, 2021, and 20152020 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules.
Natural gas imbalance receivables and payables for each of the three years ended December 31, 2017, 20162022, 2021, and 20152020 were not material and have not been included in the reserve estimates.
82
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Proved crude oil and natural gas reserves
Changes in proved reserves were as follows for the periods presented:
|
| Crude Oil |
|
| Natural Gas |
|
| Total |
| |||
Proved reserves as of December 31, 2019 |
|
| 760,187 |
|
|
| 5,154,471 |
|
|
| 1,619,265 |
|
Revisions of previous estimates |
|
| (249,845 | ) |
|
| (1,530,174 | ) |
|
| (504,874 | ) |
Extensions, discoveries and other additions |
|
| 42,106 |
|
|
| 295,686 |
|
|
| 91,387 |
|
Production |
|
| (58,745 | ) |
|
| (306,528 | ) |
|
| (109,833 | ) |
Sales of minerals in place |
|
| — |
|
|
| — |
|
|
| — |
|
Purchases of minerals in place |
|
| 3,272 |
|
|
| 27,269 |
|
|
| 7,817 |
|
Proved reserves as of December 31, 2020 |
|
| 496,975 |
|
|
| 3,640,724 |
|
|
| 1,103,762 |
|
Revisions of previous estimates |
|
| 14,574 |
|
|
| 233,966 |
|
|
| 53,569 |
|
Extensions, discoveries and other additions |
|
| 165,268 |
|
|
| 1,235,022 |
|
|
| 371,105 |
|
Production |
|
| (58,636 | ) |
|
| (370,110 | ) |
|
| (120,321 | ) |
Sales of minerals in place |
|
| (70 | ) |
|
| (469 | ) |
|
| (148 | ) |
Purchases of minerals in place |
|
| 175,419 |
|
|
| 371,546 |
|
|
| 237,343 |
|
Proved reserves as of December 31, 2021 |
|
| 793,530 |
|
|
| 5,110,679 |
|
|
| 1,645,310 |
|
Revisions of previous estimates |
|
| (85,604 | ) |
|
| (284,738 | ) |
|
| (133,061 | ) |
Extensions, discoveries and other additions |
|
| 194,848 |
|
|
| 1,203,850 |
|
|
| 395,490 |
|
Production |
|
| (72,827 | ) |
|
| (442,980 | ) |
|
| (146,657 | ) |
Sales of minerals in place |
|
| (25 | ) |
|
| (712 | ) |
|
| (144 | ) |
Purchases of minerals in place |
|
| 59,617 |
|
|
| 259,253 |
|
|
| 102,826 |
|
Proved reserves as of December 31, 2022 |
|
| 889,539 |
|
|
| 5,845,352 |
|
|
| 1,863,764 |
|
Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | |||||||
Proved reserves as of December 31, 2014 | 866,360 | 2,908,386 | 1,351,091 | ||||||
Revisions of previous estimates | (246,840 | ) | (302,143 | ) | (297,198 | ) | |||
Extensions, discoveries and other additions | 134,764 | 710,453 | 253,173 | ||||||
Production | (53,517 | ) | (164,454 | ) | (80,926 | ) | |||
Sales of minerals in place | (253 | ) | (456 | ) | (329 | ) | |||
Purchases of minerals in place | — | — | — | ||||||
Proved reserves as of December 31, 2015 | 700,514 | 3,151,786 | 1,225,811 | ||||||
Revisions of previous estimates | (99,966 | ) | (63,057 | ) | (110,474 | ) | |||
Extensions, discoveries and other additions | 97,587 | 911,062 | 249,430 | ||||||
Production | (46,850 | ) | (195,240 | ) | (79,390 | ) | |||
Sales of minerals in place | (8,057 | ) | (14,733 | ) | (10,513 | ) | |||
Purchases of minerals in place | — | — | — | ||||||
Proved reserves as of December 31, 2016 | 643,228 | 3,789,818 | 1,274,864 | ||||||
Revisions of previous estimates | (77,779 | ) | (25,390 | ) | (82,012 | ) | |||
Extensions, discoveries and other additions | 129,895 | 661,867 | 240,206 | ||||||
Production | (50,536 | ) | (228,159 | ) | (88,562 | ) | |||
Sales of minerals in place | (4,365 | ) | (64,989 | ) | (15,197 | ) | |||
Purchases of minerals in place | 506 | 7,134 | 1,696 | ||||||
Proved reserves as of December 31, 2017 | 640,949 | 4,140,281 | 1,330,995 |
Revisions of previous estimates.
RevisionsRevisions for 2021 are comprised of (i) upward price revisions of 92 MMBo and 458 Bcf (totaling 168 MMBoe) due to the significant increase in average crude oil and natural gas prices in 2021 compared to 2020 resulting from the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals, (ii) the removal of 31 MMBo and 155 Bcf (totaling 57 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (iii) downward revisions of 12 MMBo and 263 Bcf (totaling 56 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, during the year resulted in 7 MMBo of(iv) downward revisions to crudefor oil reserves of 35 MMBo and 11 Bcf of upward revisions tofor natural gas reserves of 195 Bcf (netting to 52 MMBoe of downward revisions) due to changes in 2017.
Revisions for 2020 are comprised of (i) the removal of 50 MMBo and 345 Bcf (totaling 107 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to a reduction in the scope of future drilling programs based on adverse market conditions, reduced demand, and lower prices caused by the COVID-19 pandemic and our resulting allocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (ii) downward revisions of 29 MMBo and 172 Bcf (totaling 58 MMBoe) from the removal of PUD reserves due to changes in economics, performance, and other factors, (iii) downward price revisions of 214 MMBo and 1,043 Bcf (totaling 388 MMBoe) due to a significant decrease in average crude oil and natural gas prices in 2020 compared to 2019 resulting from the economic turmoil caused by the COVID-19 pandemic and other factors, and (iv) net upward revisions for oil reserves of 43 MMBo and 31 Bcf (totaling 48 MMBoe) due to changes in ownership interests, operating costs, anticipated production, and other factors.
Extensions, discoveries and other additions
.83
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
proved reserve additions totaled 69 MMBo and 241 Bcf (totaling 109 MMBoe) in the Bakken, SCOOP,29 MMBo and STACK plays. Proved reserve additions751 Bcf (totaling 154 MMBoe) in the Bakken totaled 106Anadarko Basin, 13 MMBo and 25332 Bcf (totaling 14818 MMBoe) in the Powder River Basin, and reserve additions in SCOOP totaled 1684 MMBo and 224178 Bcf (totaling 53114 MMBoe) for the year ended December 31, 2017. Additionally, 2017 extensions and discoveries were impacted by successful drilling and completion results in the STACK play, resulting in proved reserve additions of 8 MMBo and 185 Bcf (totaling 39 MMBoe) in 2017.
Sales of minerals in place.
Purchases of minerals in place. See Note 2. Property Acquisitions for discussion of notable property acquisitions for the years ended December 31, 2022, 2021, and 2020.
The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2017, 20162022, 2021, and 2015:2020:
|
| December 31, |
| |||||||||
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Proved Developed Reserves |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 454,299 |
|
|
| 424,153 |
|
|
| 281,906 |
|
Natural Gas (MMcf) |
|
| 3,486,774 |
|
|
| 2,901,147 |
|
|
| 2,073,011 |
|
Total (MBoe) |
|
| 1,035,428 |
|
|
| 907,678 |
|
|
| 627,407 |
|
Proved Undeveloped Reserves |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 435,240 |
|
|
| 369,377 |
|
|
| 215,069 |
|
Natural Gas (MMcf) |
|
| 2,358,578 |
|
|
| 2,209,532 |
|
|
| 1,567,713 |
|
Total (MBoe) |
|
| 828,336 |
|
|
| 737,632 |
|
|
| 476,355 |
|
Total Proved Reserves |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 889,539 |
|
|
| 793,530 |
|
|
| 496,975 |
|
Natural Gas (MMcf) |
|
| 5,845,352 |
|
|
| 5,110,679 |
|
|
| 3,640,724 |
|
Total (MBoe) |
|
| 1,863,764 |
|
|
| 1,645,310 |
|
|
| 1,103,762 |
|
December 31, | |||||||||
2017 | 2016 | 2015 | |||||||
Proved Developed Reserves | |||||||||
Crude oil (MBbl) | 318,707 | 290,210 | 326,798 | ||||||
Natural Gas (MMcf) | 1,699,161 | 1,370,620 | 1,190,343 | ||||||
Total (MBoe) | 601,901 | 518,646 | 525,188 | ||||||
Proved Undeveloped Reserves | |||||||||
Crude oil (MBbl) | 322,242 | 353,018 | 373,716 | ||||||
Natural Gas (MMcf) | 2,441,120 | 2,419,198 | 1,961,443 | ||||||
Total (MBoe) | 729,094 | 756,218 | 700,623 | ||||||
Total Proved Reserves | |||||||||
Crude oil (MBbl) | 640,949 | 643,228 | 700,514 | ||||||
Natural Gas (MMcf) | 4,140,281 | 3,789,818 | 3,151,786 | ||||||
Total (MBoe) | 1,330,995 | 1,274,864 | 1,225,811 |
Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered from new wells on undrilled acreage or from existing wells that require relatively major capital expenditures to recover.recover, including most wells where drilling has occurred but the wells have not been completed. Natural gas is converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil.
84
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves
The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10%10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.
The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2017, 20162022, 2021, and 2015.
|
| December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Future cash inflows |
| $ | 115,338,240 |
|
| $ | 67,034,046 |
|
| $ | 21,334,235 |
|
Future production costs |
|
| (26,570,673 | ) |
|
| (18,837,000 | ) |
|
| (7,750,834 | ) |
Future development and abandonment costs |
|
| (9,651,656 | ) |
|
| (7,751,678 | ) |
|
| (3,950,752 | ) |
Future income taxes (1) |
|
| (16,158,309 | ) |
|
| (7,862,849 | ) |
|
| (724,569 | ) |
Future net cash flows |
|
| 62,957,602 |
|
|
| 32,582,519 |
|
|
| 8,908,080 |
|
10% annual discount for estimated timing of cash flows |
|
| (31,050,041 | ) |
|
| (15,946,126 | ) |
|
| (4,254,515 | ) |
Standardized measure of discounted future net cash flows |
| $ | 31,907,561 |
|
| $ | 16,636,393 |
|
| $ | 4,653,565 |
|
December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Future cash inflows | $ | 42,574,897 | $ | 31,008,587 | $ | 36,551,672 | ||||||
Future production costs | (11,159,362 | ) | (9,175,410 | ) | (10,869,493 | ) | ||||||
Future development and abandonment costs | (6,487,097 | ) | (6,452,647 | ) | (6,935,958 | ) | ||||||
Future income taxes (1) | (3,488,755 | ) | (3,018,839 | ) | (3,717,612 | ) | ||||||
Future net cash flows | 21,439,683 | 12,361,691 | 15,028,609 | |||||||||
10% annual discount for estimated timing of cash flows | (10,969,506 | ) | (6,851,468 | ) | (8,552,325 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 10,470,177 | $ | 5,510,223 | $ | 6,476,284 |
The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $47.03, $35.57,$89.47, $62.19, and $41.63$34.34 per barrel at December 31, 2017, 20162022, 2021, and 2015,2020, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $3.00, $2.14,$6.12, $3.46, and $2.35$1.17 per Mcf at December 31, 2017, 20162022, 2021, and 2015,2020, respectively. Future cash flows are reduced by estimated future costs to develop and produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions. The expected tax benefits to be realized from the utilization of net operating loss carryforwards and tax credits are used in the computation of future income tax cash flows.
The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years.
|
| December 31, |
| |||||||||
In thousands |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
Standardized measure of discounted future net cash flows at January 1 |
| $ | 16,636,393 |
|
| $ | 4,653,565 |
|
| $ | 10,461,641 |
|
Extensions, discoveries and improved recoveries, less related costs |
|
| 7,331,375 |
|
|
| 2,985,056 |
|
|
| 187,981 |
|
Revisions of previous quantity estimates |
|
| (3,096,189 | ) |
|
| 816,674 |
|
|
| (2,952,489 | ) |
Changes in estimated future development and abandonment costs |
|
| 1,283,405 |
|
|
| 706,168 |
|
|
| 4,760,286 |
|
Purchases (sales) of minerals in place, net |
|
| 1,852,313 |
|
|
| 3,408,365 |
|
|
| 53,742 |
|
Net change in prices and production costs |
|
| 15,251,976 |
|
|
| 9,396,945 |
|
|
| (6,912,031 | ) |
Accretion of discount |
|
| 2,049,284 |
|
|
| 489,273 |
|
|
| 1,183,993 |
|
Sales of crude oil and natural gas produced, net of production costs |
|
| (8,406,208 | ) |
|
| (4,757,483 | ) |
|
| (1,806,758 | ) |
Development costs incurred during the period |
|
| 1,302,693 |
|
|
| 683,212 |
|
|
| 863,101 |
|
Change in timing of estimated future production and other |
|
| 1,899,889 |
|
|
| 1,871,903 |
|
|
| (2,325,024 | ) |
Change in income taxes |
|
| (4,197,370 | ) |
|
| (3,617,285 | ) |
|
| 1,139,123 |
|
Net change |
|
| 15,271,168 |
|
|
| 11,982,828 |
|
|
| (5,808,076 | ) |
Standardized measure of discounted future net cash flows at December 31 |
| $ | 31,907,561 |
|
| $ | 16,636,393 |
|
| $ | 4,653,565 |
|
December 31, | ||||||||||||
In thousands | 2017 | 2016 | 2015 | |||||||||
Standardized measure of discounted future net cash flows at January 1 | $ | 5,510,223 | $ | 6,476,284 | $ | 18,433,034 | ||||||
Extensions, discoveries and improved recoveries, less related costs | 1,462,629 | 786,587 | 1,091,283 | |||||||||
Revisions of previous quantity estimates | (1,004,355 | ) | (794,785 | ) | (2,156,028 | ) | ||||||
Changes in estimated future development and abandonment costs | 743,657 | 1,651,218 | 5,008,731 | |||||||||
Sales of minerals in place, net | (41,077 | ) | (90,390 | ) | (7,768 | ) | ||||||
Net change in prices and production costs | 3,808,116 | (2,003,163 | ) | (16,111,142 | ) | |||||||
Accretion of discount | 665,507 | 798,597 | 1,843,303 | |||||||||
Sales of crude oil and natural gas produced, net of production costs | (2,450,474 | ) | (1,595,281 | ) | (2,002,997 | ) | ||||||
Development costs incurred during the period | 1,045,875 | 454,983 | 1,394,584 | |||||||||
Change in timing of estimated future production and other | 948,519 | (538,665 | ) | (3,844,259 | ) | |||||||
Change in income taxes | (218,443 | ) | 364,838 | 2,827,543 | ||||||||
Net change | 4,959,954 | (966,061 | ) | (11,956,750 | ) | |||||||
Standardized measure of discounted future net cash flows at December 31 | $ | 10,470,177 | $ | 5,510,223 | $ | 6,476,284 |
85
Quarter ended | ||||||||||||||||
In thousands, except per share data | March 31 | June 30 | September 30 | December 31 | ||||||||||||
2017 | ||||||||||||||||
Total revenues (1) | $ | 685,427 | $ | 661,486 | $ | 726,743 | $ | 1,047,172 | ||||||||
Gain on crude oil and natural gas derivatives, net (1) | $ | 46,858 | $ | 28,022 | $ | 8,602 | $ | 8,165 | ||||||||
Property impairments (2) | $ | 51,372 | $ | 123,316 | $ | 35,130 | $ | 27,552 | ||||||||
Litigation settlement (3) | $ | — | $ | — | $ | — | $ | 59,600 | ||||||||
Gain (loss) on sale of assets, net (4) | $ | (3,638 | ) | $ | 780 | $ | 3,562 | $ | 54,420 | |||||||
Income (loss) from operations | $ | 77,221 | $ | (29,041 | ) | $ | 91,753 | $ | 309,468 | |||||||
Net income (loss) (5) | $ | 469 | $ | (63,557 | ) | $ | 10,621 | $ | 841,914 | |||||||
Net income (loss) per share: | ||||||||||||||||
Basic | $ | — | $ | (0.17 | ) | $ | 0.03 | $ | 2.27 | |||||||
Diluted | $ | — | $ | (0.17 | ) | $ | 0.03 | $ | 2.25 | |||||||
2016 | ||||||||||||||||
Total revenues (1) | $ | 453,174 | $ | 451,211 | $ | 526,199 | $ | 549,689 | ||||||||
Gain (loss) on crude oil and natural gas derivatives, net (1) | $ | 42,112 | $ | (82,257 | ) | $ | 15,668 | $ | (47,382 | ) | ||||||
Property impairments (2) | $ | 78,927 | $ | 66,112 | $ | 57,689 | $ | 34,564 | ||||||||
Gain on sale of assets, net (4) | $ | 109 | $ | 96,907 | $ | 6,158 | $ | 201,315 | ||||||||
Income (loss) from operations | $ | (239,103 | ) | $ | (110,547 | ) | $ | (93,183 | ) | $ | 155,299 | |||||
Loss on extinguishment of debt (6) | $ | — | $ | — | $ | — | $ | 26,055 | ||||||||
Net income (loss) | $ | (198,326 | ) | $ | (119,402 | ) | $ | (109,621 | ) | $ | 27,670 | |||||
Net income (loss) per share: | ||||||||||||||||
Basic | $ | (0.54 | ) | $ | (0.32 | ) | $ | (0.30 | ) | $ | 0.07 | |||||
Diluted | $ | (0.54 | ) | $ | (0.32 | ) | $ | (0.30 | ) | $ | 0.07 |
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
There have been no changes in accountants or any disagreements with accountants.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of December 31, 20172022 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 20172022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors during the fourth quarter of 20172022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
86
Management’s Report on Internal Control Over Financial Reporting
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our Company’s management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in
Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on our evaluation under the framework in
Internal Control—Integrated Framework (2013), the management of our Company concluded that our internal control over financial reporting was effective as of December 31,/s/ Harold G. Hamm
President and Chief Executive Officer
/s/ John D. Hart
Chief Financial Officer and Treasurer
February 21, 2018
87
Item 9B. Other Information
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
None.
88
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information as to Item 10 will be set forth in the Proxy Statement for the Annual Meeting of Shareholdersan amendment to this Form 10-K to be held in May 2018 (the “Annual Meeting”)filed on Form 10-K/A with the Securities and Exchange Commission no later than 120 days after the end of our fiscal year covered by this report and is incorporated herein by reference.
Item 11. Executive Compensation
Information as to Item 11 will be set forth in an amendment to this Form 10-K to be filed on Form 10-K/A with the Proxy Statement forSecurities and Exchange Commission no later than 120 days after the Annual Meetingend of our fiscal year covered by this report and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and |
Information
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information as to Item 13 will be set forth in an amendment to this Form 10-K to be filed on Form 10-K/A with the Proxy Statement forSecurities and Exchange Commission no later than 120 days after the Annual Meetingend of our fiscal year covered by this report and is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
Information as to Item 14 will be set forth in an amendment to this Form 10-K to be filed on Form 10-K/A with the Proxy Statement forSecurities and Exchange Commission no later than 120 days after the Annual Meetingend of our fiscal year covered by this report and is incorporated herein by reference.
89
PART IV
Item 15. Exhibits and Financial Statement Schedules
The consolidated financial statements of Continental Resources, Inc. and Subsidiaries and the Report of Independent Registered Public Accounting Firm are included in Part II, Item 8 of this report. Reference is made to the accompanying Index to Consolidated Financial Statements.
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes thereto.
The exhibits required to be filed or furnished pursuant to Item 601 of Regulation S-K are set forth below.
3.1* | ||
3.2* | ||
4.1 | ||
4.2 | ||
4.3 | ||
4.4 | ||
4.5 | ||
10.1*† | ||
10.2 | ||
90
10.3 | ||
10.4 | ||
10.5 | ||
10.6† | ||
10.7† | ||
10.8† | ||
10.9*† | ||
10.10*† | ||
10.11*† | ||
10.12*† | ||
21* | ||
31.1* | ||
31.2* | ||
32** | ||
99* | ||
91
101.INS* | Inline XBRL Instance Document - the Inline XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document | |
101.SCH* | Inline XBRL Taxonomy Extension Schema Document | |
101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
* Filed herewith
** Furnished herewith
† Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.
92
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Continental Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONTINENTAL RESOURCES, INC. | ||
By: | / | |
Name: | Doug Lawler | |
Title: | President and Chief Executive Officer | |
Date: | February |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Continental Resources, Inc. and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ HAROLD G. HAMM | Executive Chairman Director | February 22, 2023 | ||
Harold G. Hamm | ||||
/s/ DOUG LAWLER | President, Chief Executive Officer, (principal executive officer) | February | ||
Doug Lawler | ||||
/s/ SHELLY LAMBERTZ | Executive Vice President, Chief Culture and Administrative Officer and Director | February 22, 2023 | ||
Shelly Lambertz | ||||
/s/ JOHN D. HART | Chief Financial Officer and Executive Vice President of Strategic Planning (principal financial and accounting officer) | February | ||
John D. Hart | ||||