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:
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.
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, 2017.2021. We had no PUD reserves at December 31, 20172021 that remain undevelopedundrilled beyond five years from the date of initial booking.
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, 20172021 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 representatives of Ryder Scott and by our internal technical staff 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—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 3337 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—Corporate Reserves reports directly to our Vice Chairman of Strategic Growth Initiatives. The reserves estimates are reviewed and approved by certain members of the Company's President and certain other members of seniorexecutive management.
Provided below are sensitivities illustrating the potential impact on our estimated proved reserves, Standardized Measure, and PV-10 at December 31, 20172021 under different commodity price scenarios for crude oil and natural gas. In these sensitivities, all factors other than the commodity price assumption have been held constant for each well. These sensitivities demonstrate the impact that changing commodity prices may have on estimateddo not take into account a potential increase in our drilling activities and associated booking of additional proved reserves Standardized Measure, and PV-10that may occur at higher commodity prices and there is no assurance thesethe outcomes reflected below will be realized.
The crude oil price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under variouscertain crude oil price scenarios, with natural gas prices being held constant at the 20172021 average first-day-of-the-month price of $2.98$3.60 per MMBtu.
Drilling Activity
During the three years ended December 31, 2017,2021, we drilledparticipated in the drilling and completedcompletion of exploratory and development wells as set forth in the table below:below. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
Exploratory wells: | | | | | | | | | | | | |
Crude oil | | 11 | | | 8.0 | | | 1 | | | — | | | 2 | | | 1.6 | |
Natural gas | | 2 | | | 1.9 | | | 1 | | | — | | | 4 | | | 1.8 | |
Dry holes | | — | | | — | | | 1 | | | 0.9 | | | — | | | — | |
Total exploratory wells | | 13 | | | 9.9 | | | 3 | | | 0.9 | | | 6 | | | 3.4 | |
Development wells: | | | | | | | | | | | | |
Crude oil | | 376 | | | 144.6 | | | 300 | | | 115.5 | | | 615 | | | 222.9 | |
Natural gas | | 38 | | | 20.3 | | | 31 | | | 15.9 | | | 68 | | | 9.7 | |
Dry holes | | — | | | — | | | — | | | — | | | — | | | — | |
Total development wells | | 414 | | | 164.9 | | | 331 | | | 131.4 | | | 683 | | | 232.6 | |
Total wells | | 427 | | | 174.8 | | | 334 | | | 132.3 | | | 689 | | | 236.0 | |
|
| | | | | | | | | | | | | | | | | | |
| | 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 |
|
As of December 31, 2017,2021, there were 475393 gross (179(153 net)operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.
Summary of Crude Oil and Natural Gas Properties and Projects
In the following discussion, we review our budgeted number of wells and capital expenditures for 20182022 in our key operating areas. Our 20182022 capital budget, has been set based on an expectationour current expectations of commodity prices and costs, is expected to be funded from operating cash flows. 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, available cash flows, in order to minimizeunbudgeted acquisitions, actual drilling and completion results, the incurrenceavailability of new debt. If cash flows are materially impacted by a declinedrilling and completion rigs and other services and equipment, the availability of transportation and processing capacity, changes in commodity prices, we have the ability to reduceand regulatory, technological and competitive developments. We monitor our capital expenditures or utilize the availability of our revolving credit facility if needed to fund our operations. Conversely, higherspending closely based on actual and projected cash flows resulting from an increase inand may scale back our spending should commodity prices could result in increased capital expenditures.materially decrease from current levels.
The following table provides information regarding well counts and 2018 budgeted capital expenditures by operating area.for 2022. |
| | | | | | | | | | |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | |
| | 2022 Plan |
| | Gross wells (1) | | Net wells (1) | | Capital expenditures (in millions) (2) |
| |
Bakken | | 264 | | | 116 | | | $ | 800 | |
Powder River Basin | | 34 | | | 20 | | | 200 | |
Oklahoma | | 117 | | | 41 | | | 400 | |
Permian Basin | | 49 | | | 46 | | | 400 | |
Total exploration and development | | 464 | | | 223 | | | $ | 1,800 | |
Land | | | | | | 127 | |
Mineral acquisitions attributable to Continental (3) | | | | | | 23 | |
Capital facilities, workovers, water infrastructure, and other | | | | | | 344 | |
Seismic | | | | | | 6 | |
2022 capital budget attributable to Continental | | | | | | $ | 2,300 | |
Mineral acquisitions attributable to Franco-Nevada (3) | | | | | | 91 | |
Total 2022 capital budget (4) | | | | | | $ | 2,391 | |
(1) Represents operated and non-operated wells expected to have first production in 2018.2022.
(2) Represents total capital expenditures for operated and non-operated wells expected to have first production in 20182022 and wells spud that will be in the process of drilling, completing or waiting on completion as of year-end 2018.2022.
(3) Represents planned spending for mineral acquisitions by The Mineral Resources Company II, LLC ("TMRC II") under our relationship with Franco-Nevada Corporation described in Part II, Item 8. Notes to Consolidated Financial Statements—Note 17. Noncontrolling Interests. Continental holds a controlling financial interest in TMRC II and therefore consolidates the financial results and capital expenditures of the entity. With a carry structure in place, Continental will fund 20% of 2022 planned spending, or $23 million, and Franco-Nevada will fund the remaining 80%, or $91 million.
(4) Amount excludes the $450 million purchase price for our pending acquisition of properties in the Powder River Basin as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 20. Subsequent Events.
North Region
Our properties in the North region represented 50%46% of our total proved reserves as of December 31, 20172021 and 61%55% of our average daily Boe production for the fourth quarter of 2017. Our average daily production from such properties was 175,563Boe per day for the fourth quarter of 2017, an increase of 48% from the comparable 2016 period due to increased drilling and completion activities in 2017.2021. Our principal producing properties in the North region are primarily located in the Bakken field.field of North Dakota and Montana and our recently acquired properties in the Powder River Basin of Wyoming.
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 leading producer, leasehold owner and operator in the Bakken. As of December 31, 2017,2021, we controlled one of the largest leasehold positions in the Bakken with approximately 1.31.2 million gross (801,500(771,900 net) acres under lease.
Our total Bakken production averaged 165,598175,585 Boe per day for the fourth quarter of 2017, up 58%2021, down 4% from the 20162020 fourth quarter. For the year ended December 31, 2017,2021, our average daily Bakken production increased 12% over 2016. We increased our7% compared to 2020, reflecting the impact of voluntary production curtailments in 2020 and additional drilling and well completion activities in the Bakken in 2017, particularly in the second half of the year, in response to stabilization and improvement in crude oil prices.2021. In 2017,2021, we participated in the drilling and completion of 370252 gross (145(102 net) wells in the Bakken compared to 192188 gross (38(77 net) wells completed in 2016.2020. Our 20172021 activities in the Bakken focused on ongoing multi-zone unit development of de-risked, higher rate-of-return areas in core partsareas of North Dakota and the testing of various optimized completion methods aimed at improving crude oil recoveries and rates of return.play.
Our Bakken properties represented 48%43% of our total proved reserves at December 31, 20172021 and 58%52% of our average daily Boe production for the 20172021 fourth quarter. Our total proved Bakken field reserves as of December 31, 20172021 were 636708 MMBoe, an increase of 7%39% compared to December 31, 20162020 primarily 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 higherimproved commodity prices in 2017.prices. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,2521,254 gross (656(701 net) wells as of December 31, 2017.2021.
For 2022, our budget for exploration and development capital expenditures in the Bakken is $800 million. In response to the stabilization and improvement in crude oil prices in late 2017 and early 20182022, we plan to increase our activities in North Dakota Bakken in 2018 relative to 2017. In 2018, we plan to investaverage approximately $1.19 billion in the play, which includes $413 million for the completionsix operated rigs and initiation 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 as of December 31, 2017. Additionally, we plan to use, on average, six to seventwo well completion crews in North Dakotathe Bakken throughout 2018, consistent with our current activity levels.and expect to have first production on 264 gross (116 net) operated and non-operated wells during the year. Our 20182022 drilling and completion activities in the Bakken will continue to focus on core parts of North Dakota Bakkenmulti-zone unit development in areas that provide opportunities to improve capital efficiency, reduce finding and development costs, and improve recoveries and rates of return.return, and maximize cash flows.
Powder River Basin
Our production in the Powder River Basin averaged 7,189 Boe per day for the fourth quarter of 2021. During 2021, we participated in the drilling and completion of 10 gross (8 net) wells in the play. Our Powder River properties represented 2% of our total proved reserves at December 31, 2021 and 2% of our average daily Boe production for the 2021 fourth quarter. Our proved reserves in the play totaled 32 MMBoe as of December 31, 2021 and our inventory of proved undeveloped drilling locations totaled 55 gross (34 net) wells.
For 2022, our budget for exploration and development capital expenditures in the Powder River Basin is $200 million. In 2022, we plan to average approximately two operated rigs and one well completion crew in the play and expect to have first production on 34 gross (20 net) operated and non-operated wells during the year.
South Region
Our properties in the South region represented 50%54% of our total proved reserves as of December 31, 20172021 and 39%45% of our average daily Boe production for the fourth quarter of 2017. For the 2017 fourth quarter, our average daily production from such properties was 111,422 Boe per day, an increase of 22% from the comparable period in 2016.2021. Our principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.
SCOOP
The SCOOP play currently extends across Garvin, Grady, Stephens, Carter, McClain and Love counties in Oklahoma and contains crude oil and condensate-rich fairways as delineated by numerous industry wells. our recently acquired properties in the Permian Basin of Texas.
Oklahoma
We are a leading producer, leasehold owner and operator in the SCOOP play.Oklahoma. As of December 31, 2017,2021, we controlled one of the largest leasehold positions in SCOOPOklahoma with approximately 491,100801,700 gross (276,900(448,300 net)acres under lease.
Our SCOOP leasehold has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formationproperties in Oklahoma. In recent years, our drilling activities have resulted in the vertical expansion of our SCOOP Woodford position with discoveries of the SCOOP Springer and Sycamore formations, which are located directly above the Woodford formation. Located in the heart of our SCOOP acreage, our Springer and Sycamore positions supplement our Woodford leasehold and expand our resource potential and inventory in the play.
We engaged in limited drilling and completion activities in SCOOP in 2017, choosing instead to allocate capital to other areas that offered more advantageous opportunities and rates of return. 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.
SCOOPOklahoma represented 37%41% of our total proved reserves as of December 31, 20172021 and 22%43% of our average daily Boe production for the fourth quarter of 2017.2021. Production in SCOOPOklahoma averaged 62,242146,131 Boe per day during the fourth quarter of 2017,2021, down 2% compared to the 20162020 fourth quarter. For the year ended December 31, 2017,2021, average daily production in SCOOP decreased 7%Oklahoma increased 9% compared to 2016,2020, reflecting natural declinesthe impact of voluntary production curtailments in production2020 and limitedadditional drilling and completion activities in 2017.2021. We participated in the drilling and completion of 77161 gross (20(63 net) wells in SCOOPOklahoma during 20172021 compared to 72145 gross (28(54 net) wells in 2016. Proved2020. Our proved reserves in SCOOP totaled 492 MMBoeOklahoma as of December 31, 2017,2021 totaled 679 MMBoe, an increase of 4%18% compared to December 31, 20162020 primarily 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 higherimproved commodity prices in 2017.prices. Our inventory of proved undeveloped drilling locations in SCOOPOklahoma totaled 336313 gross (230(170 net) wells as of December 31, 2017.2021.
For 2022, our aggregate budget for exploration and development capital expenditures in Oklahoma is $400 million. In 2018,2022, we plan to invest approximately $465 million to drill, complete and initiate production on 160 gross (44 net) operated and non-operated wells in the SCOOP play. We plan to average approximately seven operated rigs and onetwo well completion crewcrews in SCOOP throughout 2018, an increase from five rigs as of December 31, 2017.Oklahoma and expect to have first production on 117 gross (41 net) operated and non-operated wells during the year. Our 2018 drilling program2022 activities will continue to focus on expanding the known productive extent of the SCOOP Woodford, Springer and Sycamore formations, while focusing oncontinued development in areas that provide opportunities for converting undeveloped acreage to acreage held by production, increasingimprove capital efficiency, reducingreduce finding and development costs, improve recoveries and improving rates of return.return, and maximize cash flows.
STACKPermian Basin
STACK is a significant resource play locatedProved reserves associated with our Permian Basin properties acquired in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. As of December 31, 2017, we controlled one of the largest leasehold positions in STACK with approximately 389,400 gross (212,400 net) acres under lease. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma where we believe the reservoirs are typically thicker and deliver superior production rates relative to normal-pressured areas of the STACK petroleum system.
Building on early success achieved from our initial STACK drilling activities in mid-2015, we significantly increased our leasing and drilling activities in the play in 2016 and 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.
Through our 2016 and 2017 activities in STACK, we have successfully tested productive zones in the play, applied optimized completions to improve recoveries, demonstrated repeatability of results, reduced drilling times, reduced well costs, and de-risked a sizeable portion of our acreage in the play. Due to the success of these efforts, STACK has become another significant growth platform for us and is expected to be an important contributor to our long-term growth. To facilitate future development of our STACK acreage, we continue to increase our water recycling and distribution capabilities in the play. Additionally, we continue to increase our access to gathering and takeaway capacity to handle crude oil and natural gas production expected from future development of the play.
Our STACK properties represented 13%late 2021 totaled 203 MMBoe, representing 12% of our total proved reserves as of December 31, 2017 and 17% of2021. Production from our average daily Boe production for the fourth quarter of 2017. Production in STACK increased to an average rate of 47,914Permian properties averaged approximately 42,000 Boe per day based on two-stream reporting during the fourth quarterour short duration of 2017, up 96% over the 2016 fourth quarter dueownership from December 21, 2021 to additional drilling and completion activity resulting from our drilling program. For the year ended December 31, 2017, average daily production in STACK grew 113% over 2016. We participated2021.
For 2022, our budget for exploration and development capital expenditures in the drilling and completion of 160 gross (49 net) wells in STACK during 2017 compared to 97 gross (26 net) wells in 2016. Proved reserves increased 4% year-over-year to 167 MMBoe as of December 31, 2017 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. Our inventory of proved undeveloped drilling locations in STACK totaled 195 gross (90 net) wells as of December 31, 2017.
Permian Basin is $400 million. In 2018,2022, we plan to investaverage approximately $317 millionfour operated rigs and one well completion crew in the play and expect to drill, complete and initiatehave first production on 18049 gross (37(46 net) operated and non-operated wells in STACK. We plan to average approximately eight operated rigs in STACK throughout 2018 compared to nine rigs as of December 31, 2017. Additionally, we plan to use, on average, three completion crews in STACK throughout 2018 compared to five crews as of December 31, 2017. Our 2018 activities will focus on delineating and de-risking our acreage, expandingduring the known productive extent of the play through the completion of new density test projects, monitoring production from optimized completions, and continued refinement of our geologic and economic models in the area.
year.
Production and Price History
The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2017, 20162021, 2020 and 20152019 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2017 (North Dakota Bakken2021.
| | | | | | | | | | | | | | | | | | | | |
| | Year ended December 31, |
| | 2021 | | 2020 | | 2019 |
Net production volumes: | | | | | | |
Crude oil (MBbls) | | | | | | |
North Dakota Bakken | | 40,121 | | | 40,052 | | | 52,420 | |
SCOOP | | 11,318 | | | 12,585 | | | 11,679 | |
Total Company | | 58,636 | | | 58,745 | | | 72,267 | |
Natural gas (MMcf) | | | | | | |
North Dakota Bakken | | 120,517 | | | 97,532 | | | 98,186 | |
SCOOP | | 179,553 | | | 136,410 | | | 111,436 | |
Total Company | | 370,110 | | | 306,528 | | | 311,865 | |
Crude oil equivalents (MBoe) | | | | | | |
North Dakota Bakken | | 60,207 | | | 56,308 | | | 68,784 | |
SCOOP | | 41,244 | | | 35,320 | | | 30,252 | |
Total Company | | 120,321 | | | 109,833 | | | 124,244 | |
Average net sales prices (1): | | | | | | |
Crude oil ($/Bbl) | | | | | | |
North Dakota Bakken | | $ | 63.24 | | | $ | 33.53 | | | $ | 50.96 | |
SCOOP | | 66.46 | | | 37.88 | | | 54.92 | |
Total Company | | 64.06 | | | 34.71 | | | 51.82 | |
Natural gas ($/Mcf) | | | | | | |
North Dakota Bakken | | $ | 4.52 | | | $ | 0.23 | | | $ | 1.28 | |
SCOOP | | 5.33 | | | 1.64 | | | 2.36 | |
Total Company | | 4.88 | | | 1.04 | | | 1.77 | |
Crude oil equivalents ($/Boe) | | | | | | |
North Dakota Bakken | | $ | 51.21 | | | $ | 24.24 | | | $ | 40.66 | |
SCOOP | | 41.44 | | | 19.90 | | | 29.80 | |
Total Company | | 46.24 | | | 21.47 | | | 34.56 | |
Average costs per Boe: | | | | | | |
Production expenses ($/Boe) | | | | | | |
North Dakota Bakken | | $ | 4.27 | | | $ | 4.35 | | | $ | 4.28 | |
SCOOP | | 1.24 | | | 1.06 | | | 1.21 | |
Total Company | | 3.38 | | | 3.27 | | | 3.58 | |
Production taxes ($/Boe) | | $ | 3.36 | | | $ | 1.75 | | | $ | 2.88 | |
General and administrative expenses ($/Boe) | | $ | 1.94 | | | $ | 1.79 | | | $ | 1.57 | |
DD&A expense ($/Boe) | | $ | 15.76 | | | $ | 17.12 | | | $ | 16.25 | |
(1) See Part II, Item 7. Management’s Discussion and SCOOP). InformationAnalysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for the STACK field is also presented. a discussion and calculation of net sales prices, which are non-GAAP measures.
|
| | | | | | | | | | | | |
| | 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 |
|
The following table sets forth information regarding our average daily production by region for the fourth quarter of 2017:2021:
| | | | | | | | | | | | | | | | | | | | |
| | Fourth Quarter 2021 Daily Production |
| | Crude Oil (Bbls per day) | | Natural Gas (Mcf per day) | | Total (Boe per day) |
North Region: | | | | | | |
Bakken | | 116,548 | | | 354,222 | | | 175,585 | |
Powder River Basin | | 5,704 | | | 8,912 | | | 7,189 | |
Red River Units | | 6,212 | | | — | | | 6,212 | |
South Region: | | | | | | |
Oklahoma | | 34,314 | | | 670,904 | | | 146,131 | |
Permian Basin (1) | | 3,885 | | | 6,671 | | | 4,997 | |
Other | | 31 | | | 133 | | | 54 | |
Total | | 166,694 | | | 1,040,842 | | | 340,168 | |
|
| | | | | | | | | |
| | 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 |
|
(1)The presentation of average daily 2021 fourth quarter production represents production during the period from the closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over 92 days in the fourth quarter. At the time of closing, our Permian properties produced on average approximately 42,000 Boe per day (78% oil) based on two-stream reporting.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, 2017.2021.One or more completions in the same well bore are counted as one well.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Crude Oil Wells | | Natural Gas Wells | | Total Wells |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
North Region: | | | | | | | | | | | | |
Bakken | | 5,610 | | | 1,997 | | | — | | | — | | | 5,610 | | | 1,997 | |
Powder River Basin | | 235 | | | 143 | | | 7 | | | 5 | | | 242 | | | 148 | |
Red River Units | | 267 | | | 251 | | | — | | | — | | | 267 | | | 251 | |
South Region: | | | | | | | | | | | | |
Oklahoma | | 1,214 | | | 521 | | | 943 | | | 304 | | | 2,157 | | | 825 | |
Permian Basin | | 409 | | | 318 | | | 2 | | | 1 | | | 411 | | | 319 | |
Other | | 2 | | | 2 | | | 23 | | | 2 | | | 25 | | | 4 | |
Total | | 7,737 | | | 3,232 | | | 975 | | | 312 | | | 8,712 | | | 3,544 | |
|
| | | | | | | | | | | | | | | | | | |
| | 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 |
|
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.interest are cured.
We have procured title opinions andThe 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
MostWe 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.
The majorityWe sell most of our operated natural gas 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 residue gas 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 production from non-operated properties is generally marketed at the discretion of the operators.
Environmental Stewardship
Throughout our operations, we seek to limit associated waste through emissions management and mitigation programs, increased recycling and re-use of produced water, and the use of footprint-reducing measures. Our marketingenvironmental stewardship strategies, policies, and efforts are monitored by our Board of crude oilDirectors’ Nominating, Environmental, Social and natural gas can be affected by factors beyondGovernance Committee (“Committee”), which is the primary Committee responsible for overseeing and managing our control, the effects of which cannot be accurately predicted. For a description of some of these factors, see Part I, Item 1A. Risk factors—Our business depends on crude oil and natural gas transportation, processing and refining facilities, most of which are owned by third parties.
For the year ended December 31, 2017, sales to BP p.l.c. and affiliates and Phillips 66 and affiliates accounted for approximately 11% and 11%, respectively,ESG initiatives in respect of our total crude oilbusiness goals. Our focus on continuous improvement in ESG performance has resulted in sustained, year-over-year decreases since 2016 in both greenhouse gas and naturalmethane intensities. From 2019 through 2020, the most recent reporting year, we achieved a 28% decrease in greenhouse gas revenues. No other purchaser accounted for more than 10% of our total crude oilintensity and natural gas revenues for 2017. The loss of any single purchaser will not have a material adverse effect on our operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers34% decrease in various regions.methane intensity.
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 indepressed commodity prices in recent years, the number of providers of materials and services has decreased in the regions where we operate. Further, recent supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and equipment and increased costs. As a result, the likelihood of experiencing competition and shortages of materials and services may be further increased in connection with any period of sustained commodity price recovery.
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 energy generation devices may result in reduced demand for the crude oil and natural gas we produce.
Regulation of the Crude Oil and Natural Gas Industry
OurAll 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
Sales of crude oil and natural gas liquids (“NGLs”) or condensate in the United States are not currently subject to price controls and are made at negotiated prices. Nevertheless, the U.S. Congress could enact price controls in the future. Beginning in the 1970s, the United States regulated the exportation of petroleum and petroleum products, which restricted the markets for these commodities and affected sales prices. However, in December 2015 the U.S. Congress passed a legislative bill eliminating the export restrictions beginning in January 2016.
With regard to ourOur 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.
OurWe 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.
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.
We transportFrom 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.
In 2008, the U.S. Congress passed the Rail Safety and Improvement Act, which implemented regulations governing different areas related to railroad safety. Subsequently, the FRA and PHMSA have taken several actions related to the transport of crude
oil, including but not limited to: issuing an order requiring testing, classification and handling of crude oilalternative fuels such as a hazardous material; requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas; issuing safety advisories, alerts, emergency orders and regulatory updates; conducting special unannounced inspections; issuing rules to enhance tank car standards for certain trains carrying crude oil and ethanol; and reaching agreement with the railroad industry on a series of voluntary actions it can take to improve safety. In May 2014 the U.S. DOT issued an order requiring all railroads operating trains containing large amounts of Bakken crude oil to notify state emergency response commissions about the operation of such trains through their states. The order requires each railroad operating trains containing more than 1,000,000 gallons of Bakken crude oil, or approximately 35 tank cars, in a particular state to provide the state with notification regarding the volumes of Bakken crude oil being transported, frequencies of anticipated train traffic and the route through which Bakken crude oil will be transported. Also in May 2014, the FRA and PHMSA issued a safety advisory to the rail industry strongly recommending the use of tank cars with the highest level of integrity in their fleet when transporting Bakken crude oil. In May 2015, PHMSA published a final rule which requires, among other things, enhanced tank car standards for new and existing tank cars, a classification and testing program for crude oil, and a requirement that older DOT-111 tank cars be retrofittedliquefied natural gas. Failure to comply with new tank car design standardsthe regulations may result in accordance withfines or shipping vessels being detained, thereby resulting in exportation capacity constraints that inhibit a specified timeline beginning as early as January 1, 2018. However, in December 2017 PHMSA announced it would initiate a rulemaking to rescind the May 2015 rule's requirements regarding electronically controlled pneumatic brakes. In August 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars usedthird party's ability to transport Class 3 flammable liquids between 2018 and 2029. Separately, in July 2016 PHMSA proposed a new rule to expand the applicability of comprehensivesell domestic crude oil spill response plans so that any railroad transporting a single train carrying 20 or more loaded tank cars of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train mustproduction overseas, which may have a current, comprehensive, written plan. Issuancematerial impact on the markets and prices for various grades of domestic and international crude oil. The ultimate long-term impact of the final rule remains pending.IMO regulations is uncertain.
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.
In June 2016 the Protecting Our Infrastructure of Pipelines 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 commodities and other hazardous materials. The PIPES Act includes provisions aimed at increasing inspection requirements for certain underwater crude oil pipelines; improving protection 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 use of data and technology to prevent damage and improve safety of pipeline 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 published in the federal register during the first quarter of 2018. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.
Pipeline regulations exist at the state level as well. In December 2014 the North Dakota Industrial Commission (“NDIC”) introduced rules designed to reduce the potential flammability 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 effective in April 2015 and outline a series of standards for pressure and temperature for production facilities to follow in order to separate certain liquids and gases from the crude oil prior to transport. These rules do not affect us in a way that materially differs from our similarly situated competitors.
Regulation of sales and transportation of natural gas
In 1989,We are also required to observe the U.S. Congress enactedaforementioned anti-market manipulation laws and related regulations enforced by the Natural Gas Wellhead Decontrol Act, which removed all remaining priceFERC and non-price controls affecting wellheadCFTC in connection with physical sales of natural gas and any derivative instruments relating to natural gas. The FERC, which hasAdditionally, the authority under the Natural Gas Act (“NGA”) to regulate prices, terms, and conditions for the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. However, either the U.S. Congress or the FERC (with respect to the resale of gas in interstate commerce) could re-impose price controls in the future. 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.
The FERC regulates interstate natural gas transportation rates and service conditions under the NGANatural Gas Act and the Natural Gas Policy Act of 1978, (“NGPA”), 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 make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated open access policies are necessary to improve the competitive structure of the natural gas pipeline industrybasis and to create a regulatory framework to put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. The FERC has issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage services on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. 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.
With regard to our physical salesThe gathering of natural gas, and derivative instruments relating to natural gas, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and the CFTC. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FTC and CFTC Market Manipulation Rules.” If we violate the anti-market manipulation laws and regulations, we could be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to various FERC orders, we may be required to submit reports to the FERC for some of our operations. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency and Reporting Rules.”
Gathering service, which occurs upstream of jurisdictional transmission services, is generally regulated by the states. Although its policies on gathering systems have varied in the past, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the potential to increase costs for our costs of movingpurchasers and reduce the revenues we receive for our natural gas to point of sale locations.stream. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, equitable take requirements. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels in the future. We cannot predict what effect, if any, such changes may have on us, but the natural gas industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes, including changes in the interpretation of existing requirements or programs to implement those requirements. We do not believe we would be affected by any such regulatory changesregulations 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 to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers on a comparable basis, the regulation of intrastate natural gas transportation in states in which we operate and ship natural gas on an intrastate basis 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 and could inhibit the development of LNG infrastructure.
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 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.
Other federal laws, and regulations affecting our industry
Dodd-Frank Wall Street Reform and Consumer Protection Act. In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules, and regulations to implement the new legislation. Although the CFTC has issued final regulations to implement significant aspects of the legislation, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished. Additionally, certain aspects of the Dodd-Frank Act were repealed by the U.S. Congress in 2017.
In November 2013 and December 2016, the CFTC proposed rules establishing position limits with respect to certain futures and option contracts and equivalent swaps, subject to exceptions for certain bona fide hedging. As these new position limit rules are not yet final, the impact of these provisions on us is uncertain at this time.
Pursuant to the Dodd-Frank Act, absent an exception, mandatory clearing is now required for all market participants. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet required the clearing of any other classes of swaps, including physical commodity swaps, and the trade execution requirement does not apply to swaps not subject to a clearing mandate. Althoughas we expect to qualify for the end-user exception from the clearing requirement for our swaps entered into to hedge our commercial risks, the application of the mandatory clearing requirements to other market participants, such as swap dealers, along with changes to the markets for swaps as a result of the trade execution requirement, may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract market or swap execution facility. The ultimate effect of the proposed rules and any additional regulations on our business is uncertain.
In December 2015, the CFTC issued final rules establishing minimum margin requirements for uncleared swaps for swap dealers and major swap participants. The final rules do not impose margin requirements on commercial end users. Although we expect to qualify for the end-user exception from the margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps we use for hedging. If any of our current or future swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce our liquidity and cash available for capital expenditures and could reduce our ability to manage commodity price volatility and the volatility in our cash flows.
In addition to the CFTC’s swap regulations, certain foreign jurisdictions may adopt or implement laws and regulations relating to transactions in derivatives, including margin and central clearing requirements, which in each case may affect our counterparties and the derivatives markets generally. Other rules may alter the business practices of some of our counterparties and in some cases may cause them to stop transacting in or making markets in derivatives. Moreover, federal banking regulators are reevaluating the authorization under which banking entities subject to their authority may engage in physical commodities transactions.
Although we cannot predict the ultimate outcome of these rulemakings, they could result in increased costs and cash collateral requirements for the types of derivative instruments we use or otherwise limit our ability to manage our financial and commercial risks related to fluctuations in commodity prices. Additional effects of the regulations, including increased regulatory reporting and recordkeeping costs, increased regulatory capital requirements for our counterparties, and market dislocations or disruptions could have an adverse effect on our ability to hedge risks associated with our business.
Energy Policy Act of 2005. The Energy Policy Act of 2005 (“EPAct 2005”) included a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and made significant changes to the statutory framework affecting the energy industry. For example, EPAct 2005 amended the NGA to add an anti-market manipulation provision making it unlawful for any entity to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. In January 2006 the FERC issued rules implementing the anti-market manipulation provision of EPAct 2005. These anti-market manipulation rules apply to natural gas pipelines and storage companies which provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements described further below. The EPAct 2005 also provides the FERC with the power to assess civil penalties of up to $1,000,000 per day per violation for violations of the NGA and NGPA and disgorgement of profits associated with any violation.
FERC Market Transparency and Reporting Rules. The FERC requires wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. The FERC also requires market participants to indicate whether they report prices
to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. Failure to comply with these reporting requirements could subject us to enhanced civil penalty liability under the EPAct 2005.
FTC and CFTC Market Manipulation Rules. Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the FTC. Under the EISA, the FTC issued its Petroleum Market Manipulation Rule (the “Rule”), which became effective in November 2009. The Rule prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. Under the EISA, the FTC has authority to request a court to impose fines of up to $1,000,000 per day per violation. The CFTC has also adopted anti-market manipulation regulations prohibiting, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC may assess fines of up to the greater of $1,000,000 or triple the monetary gain for violations of these anti-market manipulation regulations. Knowing or willful violations of the Commodity Exchange Act is also a felony.
Additional proposals and proceedings potentially affecting the crude oil and natural gas industry are brought before the U.S. Congress, the FERC and the courts from time to time. We cannot predict the ultimate impact these or the above laws and regulations may have on our crude oil and natural gas operations. We do not believe we will be affected in a materially different way than our similarly situated competitors.are.
Environmental regulation
General. We are subject to stringent, complex, and complexoverlapping federal, state, and local laws, rules and regulations governing environmental compliance, including the discharge of materials into the environment. These laws, rules and regulations may, among other things:
•require the acquisition of various permits to conduct exploration, drilling and production operations;
•restrict the types, quantities and concentration of various substances that can be released into the environment in connection with crude oil and natural gas drilling, production and transportation activities;
•limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals;
•require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and
•impose substantial liabilities for pollution resulting from drilling and production operations.
These 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.
In March 2017, President Donald Trump issued an Executive Order titled “Promoting Energy Independencecosts and Economic Growth” (the "March 2017 Executive Order") which states it is in the national interestproduction of the United States to promote clean and safe development of energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation. The March 2017 Executive Order requires, among other things, the executive department and agencies to review existing regulations that potentially burden the development or use of domestically produced energy resources (with particular attention to crude oil, natural gas, coal, and nuclear energy) and suspend, revise, or rescind those regulations that unduly burden the development of such resources beyond the degree necessary to protect the public interest or otherwise comply with the law. In response to the March 2017 Executive Order, certain energy and climate-related regulations proposed or enacted under previous presidential administrations have been, or are in the process of being, reviewed, suspended, revised, or rescinded, some of which are described further below. Numerous regulations impacting the crude oil and natural gas industry are not expected to be impacted by the March 2017 Executive Order and will continue to be in effect. Additionally, undoing previously existing environmental regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further regulation of our industry may stall at the federal level under the March 2017 Executive Order, certain states have pursued additional regulation of our operations and other states may do so as well.
Environmental laws, rules and regulations. Some of the existing environmental laws, rules and regulations we are subject to include: (i) regulations by the U.S. Environmental Protection Agency (“EPA”) and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the federal Comprehensive Environmental Response,
Compensation, and Liability Act and analogous state laws that may require the removal of previously disposed hazardous substances (including hazardous substances disposed of or released by prior owners or operators), the cleanup of property contamination (including groundwater contamination), and remedial lease restoration activities to prevent future contamination from prior operations; (iii) federal Department of Transportation safety laws and comparable state and local requirements; (iv) the federal Clean Air Act and comparable state and local requirements, which establish pollution control requirements for air emissions from our operations; (v) the federal Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (vi) the Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws which impose restrictions and strict controls with respect to the discharge of pollutants, including crude oil and other substances generated by our operations, into waters of the United States or state waters; (vii) the federal Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of solid and hazardous wastes, and comparable state statutes; (viii) the federal Safe Drinking Water Act ("SDWA") and analogous state laws which impose requirements relating to our underground injection activities; (ix) the National Environmental Policy Act and comparable state statutes, which require government agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment; (x) the federal Endangered Species Act and comparable state statutes, which afford protections to certain plant and animal species; (xi) the federal Migratory Bird Treaty Act, which imposes certain restrictions for the protection of migratory birds; (xii) the federal Bald and Golden Eagle Protection Act, which imposes certain restrictions for the protection of bald and golden eagles; (xiii) the federal Emergency Planning and Community Right to Know Act and comparable state statutes, which require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations, and (xiv) state regulations and statutes governing the handling, treatment, storage and disposal of technologically enhanced naturally occurring radioactive material.gas. Failure to comply with these and other laws, rules and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or performanceexpansion of projects, the issuance of orders enjoining performance of some or all of our operations, and potential litigation.litigation in a particular area. Additionally, certain of these environmental laws may result in imposition of joint and several or strict liability, which could cause us to become liable for the conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners or other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Certain environmental laws also provide for certain citizen suits, which allow persons or organizations to act in place of the government and sue operators for alleged violations of environmental laws. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental laws and regulations. The following is a description of some of the environmental laws, rules and regulations, as amended from time to time, that apply to our operations.
Air emissions and climate change. Federal, state, and local laws, rules, and regulations have been and, mayin the future, will likely be enacted to address concerns about emissions of regulated air pollutants. These laws and regulations may require us to obtain pre-approval for the effects the emissionconstruction or modification of carbon dioxide, methanecertain projects or facilities expected to produce or significantly increase air emissions, obtain and other identified “greenhouse gases” may have on the environment and climate worldwide, generally referredstrictly comply with stringent air permit standards or utilize specific equipment or technologies to as “climate change.”control emissions of certain pollutants. For example, in October 20152021, the EPA revisedU.S. Environmental Protection Agency (“EPA”) announced its intention to initiate a rule-making to reassess and lower, by the end of 2023, the current National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone, for approximately 35% ofwhich was last set by the U.S. counties, including all of the counties in North Dakota and all of the counties except for Bryan County in Oklahoma, as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue attainment or nonattainment designations for the remaining areas of the U.S. not addressedEPA under the November 2017 ruleObama Administration in the first half of 2018. Additionally, state2015. State implementation of thea revised NAAQS for ground-level ozone could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, andor result in increased expenditures for pollution control equipment, the costs of which could be significant.
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.
In addition, the EPA has adopted rulessources, requiring the monitoring and annual reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. New Source Performance Standard (“NSPS”) Subpart OOOO (“Quad O”) requires, among other things, the reduction of volatile organic compound (“VOC”) emissions from three subcategories of fractured and refractured oil and gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured oil and gas wells. All three subcategories of wells must route flowback emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” fractured and refractured wells must use reduced emission completions or “green completions.” The rule also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The rule is designed to limit emissions of VOCs, sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oilpetroleum and natural gas production facilities,system sources, and natural gas transmission compressor stations. We have modified our operations and well equipment as needed to comply with these rules. Ongoing compliance with the rules is not expected to affect us in a way that materially differsreducing methane emissions from our similarly situated competitors.
In addition, in June 2016 the EPA finalized new regulations (NSPS Subpart OOOOa, commonly referred to as “Quad Oa”) setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilitiesoperations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. In recent years, there has been considerable uncertainty surrounding regulation of methane emissions. During 2020, the Trump Administration revised performance standards for methane established in 2016 to lessen the impact of those standards and remove the transmission and storage segments from the source category for certain regulations. However, shortly after taking office in 2021, President Biden issued an effortexecutive order calling on the EPA to reducerevisit federal regulations regarding methane emissions fromand establish new or more stringent standards for existing or new sources in the oil and gas sector, by up to 45% from 2012 levels by 2025 even though there was consensus atincluding the time that oiltransmission and gas producers’ compliance with Quad O had already achieved reductions in methane emissions.
However, in June 2017, the EPA proposed to stay certain portionsstorage segments. The U.S. Congress also passed, and President Biden signed into law, a revocation of the NSPS Quad Oa rules described above for a period of two years while2020 rulemaking, effectively reinstating the rules are reconsidered in2016 standards. In response to President Trump’s March 2017 Executive Order to reduce the burden of federal regulations that may hinder economic growth and energy development. The EPA has not yet published a final rule issuing the stay, and, as a result, the Quad Oa rules are currentlyBiden’s executive order, in effect but future implementation of the Quad Oa rules is uncertain at this time. As part of its reconsideration,November 2021 the EPA may issue revised rules, the timingissued a proposed rule that, if finalized, would establish Quad Ob new source and impactQuad Oc first-time existing source standards of which is uncertain.
Additional regulation with respect toperformance for methane emissions occurred in November 2016 when the U.S. Department of Interior’s Bureau of Land Management (“BLM”) published a final rule commonly referred to as the “BLM Venting and Flaring Rule.” Similar to Quad Oa, the BLM Venting and Flaring Rule imposes requirements related to methane emissions from crude oil and natural gas sources. However, in response to President Trump’s March 2017 Executive Order, in December 2017 the BLM announced it was temporarily suspending or delaying certain requirements contained in its Venting and Flaring Rule until January 2019. That suspension is now being challenged in court and future implementation and impact of the rule remains uncertain. While additional federal regulation with respect to methane emissions appears unlikely in the near future, states may nevertheless pursue rules or enforcement actions designed to reduce methane emissions. To the extent new methane emission regulations—whether it is the BLM Venting and Flaring Rule, a prospective EPA rule targeting methane emissions from existing sources, or a state agency—impose reporting obligations on, or limit emissions of greenhouse gases from, our equipment and operations they could require us to incur costs to reduce emissions associated with our operations, but the impact of these measures is not expected to be material and will not affect us in a materially different way from our similarly situated competitors.
At an international level, in December 2015 a global climate agreement was reached in Paris at the 21st Conference of Parties organized by the United Nations under the Framework Convention on Climate Change. The agreement, which goes into effect in 2020, resulted in nearly 200 countries, originally including the United States, committing to work towards limiting global warming and agreeing to a monitoring and review process of greenhouse gas emissions. The agreement includes binding and non-binding elements and did not require ratification by the U.S. Congress. In June 2017, President Trump announced the United States will withdraw from and cease implementation of the Paris climate agreement, but indicated the U.S. may re-engage in the agreement if more favorable terms can be re-negotiated. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris climate agreement. The exit process provided for under the Paris agreement could take up to four years. The United States’ adherence to the exit process is uncertain and the terms on which the United States may reenter the Paris agreement or a separately negotiated agreement are unclear. Although the U.S. has ceased its participation in the Paris agreement, the agreement nonetheless may result in increased political pressure on the United States to ensure continued compliance with enforcement measures under the Clean Air Act and may spur further initiatives aimed at reducing greenhouse gasvolatile organic compound (VOC) emissions in the future.
While the U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of enacted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal legislation, a number of state and regional efforts have emerged aimed at tracking and reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. There has also been discussion of imposing a federal carbon tax on all fossil fuel production, though such a tax appears unlikely at this time. Although it is not possible to predict how such legislation or new regulations adopted to address greenhouse gas emissions will impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the crude oil and natural gas we producesource category. This proposed rule would apply to upstream and lower the valuemidstream facilities at oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of our reserves. Finally, some scientistsaffected emission units or processes would have concluded increasing concentrationsto comply with specific standards of greenhouse gasesperformance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operation and maintenance requirements, and so-called green well completion requirements. The EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain additional requirements that were not included in the Earth’s atmosphere mayNovember 2021 proposed rule. The EPA anticipates issuing a final rule before end-of-year 2022. Additionally, the House of Representatives version of the Build Back Better Act included a fee on methane emissions, targeting industries that produce, transport, and store natural gas throughout the United States at $900 per ton in 2023, $1,200 per ton in 2024, and $1,500 per ton in 2025 and beyond. Congress could seek to include this or a similar fee in future legislation.
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. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50%-52% reduction from 2005 levels in economy-wide net GHG emissions 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 preliminary injunction by a federal district judge in Louisiana in June 2021, effectively halting implementation of the leasing suspension. The federal government is appealing the district court decision. 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.
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. At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. These and other climatic events. Ifdevelopments in the financial sector could lead to some lenders restricting or eliminating access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce 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 addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. While we cannot predict what policies may result from this, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for acquisition, exploration, development, production, transportation, and processing activities, which could impact our business and operations. To the extent the rules impose additional reporting obligations, we could face increased costs. Furthermore, the SEC has announced it will propose rules that, among other matters, will establish a framework for the reporting of climate risks. However, no such rules have been proposed to date and we cannot predict what any such effects from such causesrules may require. To the extent rules impose additional reporting obligations, we could face increased costs. Separately, the SEC has also announced it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC was to allege that an issuer’s existing climate disclosures were to occur, they could have an adverse effect on our exploration and production operations.misleading or deficient.
Both the EPA and the state of North Dakota pursued enforcement actions in 2016 against operators related to emissions generally and alleged noncompliance with the requirements of Quad O, Quad Oa, and relevant state regulations more specifically. One such enforcement action by the EPA against an operator resulted in a consent decree between the parties
requiring the operator to incur costs associated with a civil penalty, emissions-related mitigation projects, and implementation of a robust leak detection and repair program applicable to all of the operator’s wells in North Dakota.
Finally, the U.S. Department of Justice (“DOJ”) announced in 2016 it had partnered with the Occupational Safety and Health Administration to pursue a “Worker Endangerment Initiative” seeking to promote worker safety by pursuing not only worker safety claims in connection with worker safety incidents but also environmental claims.
Environmental protection and natural gas flaring. We strive to operate in accordance with all applicable regulatory and legal requirements and have focused on continuously improving our environmental performance; however, at times circumstances may arise that adversely affect our compliance with applicable environmental requirements. We have established internal policies, procedures and processes regarding environmental matters for all employees, contractors, and vendors. In connection with our environmental initiatives, we work to identify and manage our environmental risks and the impact of our operations and continually improve our environmental compliance. However, we cannot guarantee our efforts will always be successful.
One of our environmental initiatives is the reduction of air emissions produced from our operations, particularly with respect toincluding the flaring of natural gas from our operated well sites in the Bakken field of North Dakota. North Dakota statutes permitlaw permits flaring of natural gas from a well that has not been connected to a gas gathering line for a period of one year from the date of a well’s first production. After one year, a producer is required to cap the well, connect it to a gas gathering line, find acceptable alternative uses for a percentage of the flared gas, or apply to the NDICNorth Dakota Industrial Commission ("NDIC") for a written exemption for any future flaring; otherwise, the producer is required to pay royalties and production taxes based on the volume and value of the gas flared from the unconnected well. While the NDIC ultimately determines the volume and value of any such gas flared and the applicable royalties and production taxes, the NDIC has thus far generally accepted our methods for calculating these amounts. Furthermore, the NDIC has generally accepted applications we have submitted to secure exemptions from the post-year flaring restrictions. Finally,
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.
For the year ended December 31, 2017, we delivered approximately 90% of our operated natural gas production in the North Dakota Bakken fieldWe 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.
There are environmental and financial risks associated with natural gas flaring, and we attempt to manage these risks on an ongoing basis. We have taken numerous actions to reduce flaring from our operated well sites, such as coordinating our well completion operations to coincide with well connections to gathering systems in order to minimize flaring; however, weefforts may not always be successful in these efforts. Our ultimate goal is to reduce natural gas flaring from our operated well sites as much as practicable. For example, in operating areas such as the Buffalo Red River units in South Dakota, the quality of the natural gas is not adequate to meet requirements for sale, so we employ processes to efficiently combust the gas in an effort to minimize impacts to the environment.or cost-effective. Our levels of flaring are and will be dependent uponimpacted by external factors such as investment from third parties in the development and continued operation of gas gathering systems, state regulations,and processing facilities and the granting of reasonable right-of-way access by land owners. For example, over the past year insufficient takeaway capacity in North Dakota has created challenges for all operators and contributed to an increase in volumes of flared gas. Increased emissions from a multi-well pad facility or centralized productionour facilities due to flaring could require ussubject our facilities to adhere to PSD or Title V permit requirements. We have filed several permits to construct major sources (i.e., facilities from which emissions of a criteria pollutant (e.g., carbon monoxide or volatile organic compounds) are expected to exceed 100 tons per year) relating to facilities where takeaway capacity is currently constrained and creating a potential to emit in excess of 100 tons per year.
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. Although we believe our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you the passage of more stringent laws or regulationsair emission permitting requirements, resulting in the future will not materially impact our financial position, results of operations or cash flows.increased compliance costs and potential construction delays.
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 been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies andor to induce seismic events. As a result, several federal and state agencies are studyinghave studied the environmental risks with respect to hydraulic fracturing, and proposals have been made to enact separate federal, state and local legislation that would potentially increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”("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.
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 authority to promulgateTrump Administration published a final rule rescinding the regulations.The U.S. Department of Interior appealed the decision. In December 2017, the BLM formally rescinded its March 2015 hydraulic fracturing rules, citing unjustified administrative burdens and compliance costs arising from a reassessment performed2016 final rule in response to President Trump's March 2017 Executive Order to reduce the burden of federal regulations that may hinder economic growth and energy development. In January 2018, litigationNovember 2018. Litigation challenging the BLM's rescission of2016 final rule as well as its 2018 final rule rescinding the March 20152016 rule has been pursued by various states and industry and environmental groups. While a California federal court vacated the 2018 final rules was broughtrule in July 2020, a Wyoming federal court. As of December 31, 2017, we held approximately 65,500 net undeveloped acrescourt subsequently vacated the 2016 final rule in October 2020 and, accordingly, the 2016 final rule is no longer in effect. However, appeals to those decisions are ongoing. Notwithstanding these recent legal developments, further administrative and regulatory restrictions may be adopted by the Biden Administration that could restrict hydraulic fracturing activities on federal land, representing approximately 11% of our total net undeveloped acres.lands and waters.
At the state level, severalIn 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.
Regulators in states in which we operate are considering additional requirements related to seismicity and its potential association with hydraulic fracturing. For example, the Oklahoma Corporation Commission (the “OCC”) has promulgated guidance for operators of crude oil and natural gas wells in certain seismically-active areas of the SCOOP and STACK plays in Oklahoma. The OCC's guidance provides for seismic monitoring and for implementation of mitigation procedures, which may include acurtailment or even suspension of operations in the event of concurrent seismic events within a particular radius of operations of a magnitude exceeding 2.5 on the Richter scale. The OCC may update this guidance to impose a larger monitoring area and more stringent requirements for notification and suspension of operations. If seismic events exceeding the OCC guidance thresholds were to occur near our active stimulation operations on a frequent basis, they could have an adverse effect on our operations.
We voluntarily participate in FracFocus, a national publicly accessible Internet-based registry developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. This registry, located at www.fracfocus.org, provides
our industry with an avenue to voluntarily disclose additives used in the hydraulic fracturing process. The additives used in the hydraulic fracturing process on all wells we operate are disclosed on that website.
The adoption of any future federal, state or local laws, rules or implementing regulations imposing permitting or reporting obligations on, or otherwise limiting, hydraulic fracturing processes in areas in which we operate could make it more difficult and expensive to complete crude oil and natural gas wells in low-permeability formations, increase our costs of compliance and doing business, and delay, prevent or prohibit the development of natural resources from unconventional formations. Compliance, or the consequences of our failure to comply, could have a material adverse effect on our financial condition and results of operations. At this time it is not possible to estimate the potential impact on our business if such federal or state legislation is enacted into law.
Waste water disposal. disposal. Underground injection wells are a predominant method for disposing of waste water from oil and gas activities. In response to seismic events near underground injection wells used for the disposal of oil and gas-related waste waters, federal and some state agencies are investigatinghave investigated whether such wells have caused increased seismic activity. SomeTo address concerns regarding seismicity, some states, including states in which we operate, have delayedpursued remedies that included delaying permit approvals, mandatedmandating a reduction in injection volumes, or have shutshutting down or imposedimposing moratoria on the use of injection wells. RegulatorsMoreover, regulators in states in which we operate are consideringhave implemented additional requirements related to seismicity. For example, the OCC has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of Oklahoma. These rules require, among other things, that disposal well operators conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma has adoptedutilizes a “traffic light” system wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. At the federal level, the EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. We cannot predict the EPA’s future actions in this regard.
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.
Employee Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state statuteslaws that regulate the protection of the health and safety of workers. In addition, the OSHAU.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulation under Title III of the federal superfund Amendment and Reauthorization Act and similar state statuteslaws and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local governmental authorities and citizens.
Human Capital
Employees and Labor Relations
As of December 31, 2017,2021, we employed 1,127 people. Our future success will depend partially on1,254 people, all of which were employed in the United States, with 721 employees being located at our abilitycorporate headquarters in Oklahoma City, Oklahoma and 533 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 shareholders 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 shareholders by making annual restricted stock awards to virtually all of our 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. Our Total Recordable Incident Rate (TRIR), a commonly used safety metric that measures the servicesnumber of independentrecordable incidents per 100 full-time employees and contractors during a one year period,has decreased sequentially in each of the past four years and measured 0.33 for 2021, a 61% decrease compared to perform2017.
Training and Development
We are committed to the training and development of our employees. We believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting 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.personal leave; and healthcare flexible spending accounts, among other things. In addition to these programs, we have a number of other programs designed to further promote the health and wellness of our employees. For
instance, employees at our corporate headquarters have access to our fitness center. Additionally, we have an employee assistance program that offers counseling and referral services for a broad range of personal and family situations. We also offer a wellness plan that includes annual biometric screenings, flu shots, smoking cessation programs, and healthy snack options in our break rooms to encourage total body wellness.
From the earliest days of the COVID-19 pandemic we have taken, and continue to take, proactive measures to protect the health and safety of our employees, both at work and at home. These measures have included offering free in-office testing, providing flexible work schedules for impacted employees, holding in-office vaccination clinics so that interested employees and household members could conveniently receive vaccinations as soon as possible, maintaining physical distancing policies, limiting the number of employees attending meetings, reducing the number of people at our sites, requiring the use of masks in certain circumstances, frequently and extensively disinfecting common areas, and implementing self-isolation and quarantine requirements, among other things. We are committed to maintaining best practices with our COVID-19 response protocols and will continue to work under the guidance of public health officials to ensure a safe workplace as long as COVID-19 remains a threat to our employees and communities.
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, national origin, 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 and Ethics, 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 begun implementing 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. We are working with our newly formed Diversity and Inclusion Committee to 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 the investor relations section of our website, we make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after the report is filed with or furnished to the SEC. For a current version of various corporate governance documents, including our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters for various committees of our Board of Directors, please see our website. We intend to disclose amendments to, or waivers from, our Code of Business Conduct and Ethics by posting to our website. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.
We 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”“Investors” section. Accordingly,
investors should monitor that portion of our website in addition to following our press releases, SEC filings and public conference calls and webcasts.
We electronically file periodic reports and proxy statements with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers thatregistrants file electronically with the SEC. The address of the SEC’s website is www.sec.gov.
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.
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 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 decline and you may lose all or part of your investment.
Business and Operating Risks
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.
We have hedged the majority of our forecasted 2018 natural gas production.future. Our future crude oil production and a portion of our future natural gas production is currently unhedged as of the time of this filing and directlyis exposed to continued volatility in market prices, whether favorable or unfavorable.
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:
•worldwide, domestic, and regional economic conditions impacting the supply of, and demand for, crude oil, natural gas, and natural gas;gas liquids;
•the actions of the Organization of Petroleum Exporting Countries and other petroleum producing nations;
•the nature, extent, and impact of domestic and foreign governmental laws, regulations, and taxation, including environmental laws and regulations governing the imposition of trade restrictions and tariffs;
•executive, regulatory or legislative actions by Congress, the Biden Administration, or states in which we operate;
•geopolitical events and conditions, including domestic political uncertainty or foreign regime changes that impact government energy policies;
•the level of global, national, and globalregional crude oil and natural gas exploration and production activities;
•the level of global, national, and globalregional crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;
•the level and effect of speculative trading in commodity futures markets;
•the relative strength of the United States dollar compared to foreign currencies;
•the price and quantity of imports of foreign crude oil;
•the price and quantity of exports of crude oil or liquefied natural gas from the United States;
•military and political conditions in, or affecting other, crude oil-producing and natural gas-producing countries;nations;
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulations;
•localized supply and demand fundamentals;
•the cost and availability, proximity and capacity of transportation, processing, storage and refining facilities for various quantities and grades of crude oil, natural gas, and natural gas;gas liquids;
•adverse weatherclimatic conditions, natural disasters, and natural disasters;national and global health epidemics and concerns, including the COVID-19 pandemic;
•technological advances affecting energy production and consumption;
•the effect of worldwide energy conservation and greenhouse gas emission limitations or other environmental protection efforts;
•the impact arising from increasing attention to environmental, social, and governance (“ESG”) matters; and
•the price and availability of alternative fuels or other energy sources.
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 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
action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase the borrowing costs under our revolving credit facility, and limit our ability to access capital markets and execute aspects of our business plans. As a result, substantial declines in commodity prices or extended periods of low commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash flows, liquidity and ability to finance plannedmeet our capital expendituresexpenditure needs and commitments.
A substantial portionThe 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.
A substantial portion of our producing properties is located in the Bakken field of North Dakotaset and Montana, with that area comprising approximately 55% of ourmaintain production levels has a significant impact on crude oil prices.
The Organization of Petroleum Exporting Countries ("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%of our estimated proved reserves were located in the Bakken as of December 31, 2017. Additionally, in recent years we have significantly expanded our operations in Oklahoma with our increased activity in the SCOOP and STACK plays. Our properties in Oklahoma comprised approximately 41% of our crude oil and natural gas production and approximately 31% of our crude oil and natural gas revenues for the year ended December 31, 2017. Approximately 50% of our estimated proved reserves were located in Oklahoma as of December 31, 2017.
Because of this concentration in limited geographic areas, the success and profitability of our operations may be disproportionately exposed to regional factors compared to competitors having more geographically dispersed operations. These factors include, among others: (i) the pricessupply of crude oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations such as Russia, may have a significant impact on global oil supply and natural gas produced from wellspricing. There can be no assurance that OPEC members and other oil exporting nations will comply with agreed-upon production targets, agree to further production targets in the regionsfuture, or utilize other actions to support and stabilize oil prices, nor can there be any assurance they will not increase production or deploy other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oilfield services, supplies, and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operationsactions aimed at reducing oil prices. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the Bakken field and Oklahoma may be adversely affected by severe weather events such as floods, blizzards, ice storms and tornadoes,price of oil, which can intensify competition for the items and services described above and may result in periodic shortages. The concentration of our operations in limited geographic areas also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the regions such as natural disasters, seismic events (which may result in third-party lawsuits), industrial accidents, labor difficulties, civil disturbances, public protests, or terrorist attacks. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
VolatilityOur business operations, financial position, results of operations, and cash flows have been and may continue to be materially and adversely affected by the COVID-19 pandemic.
The ongoing COVID-19 pandemic has negatively impacted, and may continue to negatively impact, the global economy which has 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. The adverse effects of COVID-19 have included and may in the future include the following:
•Reduced crude oil prices;
•Limitations on storage and transportation capacity and an inability to market our production;
•Curtailment or shutting in of production;
•Delay or cessation of drilling and completion projects;
•Insufficient production to satisfy transportation and processing commitments;
•Impairment of assets;
•Downgrades or other negative credit rating actions resulting in increased borrowing costs;
•An inability to develop acreage before lease expiration;
•A reduction in the volume and value of proved reserves from price declines, changes in drilling programs, and the effects of shutting in production;
•Increased difficulty in our ability to repay or refinance indebtedness, increase our credit facility commitments, borrow money, or raise capital;
•Disruptions in energy industry supply chains and increased rates of inflation;
•Credit losses due to insolvency of customers, joint interest owners, and counterparties;
•Cyber incidents or information security breaches resulting in information theft, data corruption, operational disruption, and/or financial marketsloss as a consequence of employees accessing information from remote work locations; and
•Shortages of drilling rigs, well completion crews, field services, personnel, and equipment in future periods of commodity price recovery.
The future impact of the pandemic on global and local economies and our business will continue to depend on future developments such as the emergence of future variant strains of COVID-19, the availability and distribution of effective medical treatments and vaccines, vaccination rates, as well as government-imposed restrictions or in global economic factorsmandates, all of which are uncertain and cannot be predicted.
Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely impactaffect our accessbusiness, 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 some of our current prospects and plans to develop our 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 businessother technologies and financial condition.the study of producing fields in the same 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.
United StatesRisks 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 global economiesnot 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 experienceoccur that cause us to curtail, delay or cancel scheduled drilling and completion projects, including but not limited to:
•abnormal pressure or irregularities in geological formations;
•shortages of or delays in obtaining equipment or qualified personnel;
•shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;
•delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;
•mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or storage facilities, or train derailments;
•restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;
•political events, public protests, civil disturbances, terrorist acts or cyber attacks;
•decreases in, or extended periods of turmoillow, crude oil and volatilitynatural gas prices;
•title problems;
•environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
•adverse climatic conditions and natural disasters;
•spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers;
•limitations in infrastructure, including transportation, processing, refining and exportation capacity, or markets for crude oil and natural gas; and
•delays imposed by or resulting from compliance with regulatory requirements including permitting.
Any of the above risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
•injury or loss of life;
•damage to or destruction of property, natural resources and equipment;
•pollution and other environmental damage;
•regulatory investigations and penalties;
•suspension of our operations;
•repair and remediation costs; and
•litigation.
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 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, 2021.
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 natural gas prices and other factors, some of which are beyond our control.
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 be materially higher or lower than the average prices used in the calculations. In addition, the use of a 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. For the year ended December 31, 2021, average prices used to calculate our estimated proved reserves were $66.56 per Bbl for crude oil and $3.60 per MMBtu for natural gas ($62.19 per Bbl for crude oil and $3.46 per Mcf for natural gas adjusted for location and quality differentials). NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity prices for January 1, 2022 and February 1, 2022 averaged $81.71 per barrel and $4.65 per MMBtu, respectively. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserves, Standardized Measure, and PV-10 Sensitivities for proved reserve sensitivities under certain increasing and decreasing commodity price scenarios.
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, 2021, approximately 45% 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, 2021 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $7.7 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 will 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 demandwill likely 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 2021, 57 MMBoe 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 37% of political uncertainty, slowing economic growth, rising interestour total net undeveloped acreage at December 31, 2021. At that date, we had leases representing 83,937 net acres expiring in 2022, 62,251 net acres expiring in 2023, and 51,094 net acres expiring in 2024.
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.condition and results of operations could be materially adversely affected.
Historically,Our business depends on crude oil and natural gas transportation, processing, refining, and export facilities, most of which are owned by third parties.
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.doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally, the consequences of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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 no later than November 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 North region crude oil production to ultimate markets on the U.S. gulf coast. Our transportation commitment on the pipeline increased from 3,550 barrels per day to 30,000 barrels per day effective August 1, 2021 in conjunction with the completion of a DAPL expansion project. This commitment 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 attributable to us in 2018 (excluding2022, excluding acquisitions, which are not budgeted) of which $1.99approximately $1.80 billion is allocated forto exploration and development drilling.activities. We may adjust our 20182022 capital spending plans upward or downward depending on market conditions.
Historically, Our 2022 capital budget, based on our capital expenditures have been financed with cash generated by operations, borrowings under our revolving credit facility and proceeds from the issuancecurrent expectations of debt and equity securities. Additionally, in recent years non-strategic asset
dispositions have provided a source of cash flow for use in reducing outstanding debt arising from our capital program. The actual amount and timing of future capital expenditures may differ materially from our estimates as a result of, among others, changes in commodity prices availableand costs, is expected to be funded from operating cash flows, lackflows. However, the sufficiency of access to capital, unbudgeted acquisitions, actual drilling and completion results, the availability of drilling and completion rigs and other services and equipment, the availability of transportation and processing capacity, and regulatory, technological and competitive developments.
Ourour cash flows from operations and access to capital areis subject to a number of variables, including but not limited to:
•the prices at which crude oil and natural gas are sold;
•the volume and value of our proved reserves;
•the volume of crude oil and natural gas we are able to produce and sell from existing wells; and
the prices at which crude oil and natural gas are sold;
•our ability to acquire, locate and produce new reserves;
our ability to dispose of assets or enter into joint development arrangements on satisfactory terms; and
the ability and willingness of our lenders to extend credit or of participants in the capital markets to invest in our senior notes or equity securities.
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 alter or increase our capitalization substantially through the issuance of debt or equity securities.
We have a revolving credit facility with lender commitments totaling $2.75$2.0 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.
We intend to finance future capital expenditures primarily through cash flows from operations, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility or proceeds from asset sales or joint development arrangements. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. If we issue additional debt a portion of our cash flows from operations will need to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital needs, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
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.
Our future financial condition and results of operations will 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, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.
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 curtail, delay or cancel scheduled drilling projects, including but not limited to:
abnormal pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment or qualified personnel;
shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;
delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;
mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or train derailments;
restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
decreases in, or extended periods of low, crude oil and natural gas prices;
limited availability of financing with acceptable terms;
title problems;
environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers;
limitations in infrastructure, including transportation, processing and refining capacity, or markets for crude oil and natural gas; and
delays imposed by or resulting from compliance with regulatory requirements including permitting.
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 will likely turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company’s current estimates of reserves could change, potentially in material amounts, in the future, in particular due to changes in commodity prices.
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 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, 2017.
In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. Our booked proved undeveloped reserves must be developed 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 will likely 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 2017, 89 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.
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 but projected into the future, about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
The prices used in calculating our estimated proved reserves are calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the year ended December 31, 2017, average prices used to calculate our estimated proved reserves were $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas ($47.03 per Bbl for crude oil and $3.00 per Mcf for natural gas adjusted for location and quality differentials). Actual future prices may be materially higher or lower than those used in our year-end estimates. NYMEX WTI crude oil and Henry Hub
natural gas first-day-of-the-month commodity prices for January 1, 2018 and February 1, 2018 averaged $63.11 per barrel and $3.40 per MMBtu, respectively. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities for proved reserve sensitivities under certain increasing and decreasing commodity price scenarios.
Actual future production, crude oil and natural gas 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 adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development activities, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control.
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.
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 be materially higher or lower than the average prices used in the calculations. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities for Standardized Measure and PV-10 sensitivities under certain increasing and decreasing commodity price scenarios.
Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:
the actual prices we receive for sales of crude oil and natural gas;
the actual cost and timing of development and production expenditures;
the timing and amount of actual production; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of costs in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the use of a 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 and risks associated with our reserves or the crude oil and natural gas industry in general. Any significant variances in timing or assumptions could materially affect the estimated present value of our reserves, which in turn could have an adverse effect on the value of our assets.
We may be required to further write down the carrying values of our crude oil and natural gas properties if commodity prices decline or our development plans change.
Accounting rules require we periodically review the carrying values of our crude oil and natural gas properties for possible impairment. Proved properties are reviewed for impairment on a field-by-field basis each quarter. We use the successful efforts method of accounting whereby the estimated future cash flows expected in connection with a 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 using a discounted cash flow model.
Based on specific market factors, prices, and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying values of our crude oil and natural gas properties. A write-down results in a non-cash charge to earnings. We have incurred impairment charges in the past and may incur additional impairment charges in the future, particularly if commodity prices decline, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our cash flows and results of operations.
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 that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success 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 and results of operations could be materially adversely affected.
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.
Certain drillingshortages and/or higher costs. For instance, recent supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and completion costs and costs of oilfield services, equipment and materials decreasedincreased costs. While we have not yet experienced material shortages in recent yearssupply as service providers reduced their costs in response to reduced demand arising from low crude oil prices. However, inflationary pressures returned in 2017 and are expected to continue in 2018 in conjunction with the stabilization and improvement in crude oil prices in recent months.
As a result of these disruptions, if they become prolonged or expand in scope the low commodity price environment in recent years, the number of providers of services, equipment, and materials decreased in the regions where we operate. Further, increased industry drilling and completion activities in recent months prompted by improvement in crude oil prices may cause shortages or higher costs of services, equipment, and materials. Suchresulting shortages or higher costs could delay the execution of our drilling and development plans including our plans to work down our large inventory of uncompleted wells, or cause us to incur expenditures not provided for in our capital budget or to not achieve the rates of return we are targeting for our development program, all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may incur substantial losses and be subject to substantial liability claims as a result of our crude oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and under-insured events could materially and adversely affect our business, financial condition or results of operations. Our crude oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:
environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
fires and explosions;
ruptures of pipelines or storage facilities;
loss of product or property damage occurring as a result of transfer to a rail car or train derailments;
personal injuries and death;
adverse weather conditions and natural disasters; and
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
injury or loss of life;
damage to or destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations;
repair and remediation costs; and
litigation.
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. The occurrence of an event not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Prospects we decide to drill may not yield crude oil or natural gas in economically producible quantities.
Prospects we decide to drill that do not yield crude oil or natural gas in economically producible quantities may adversely affect our results of operations and financial condition. In this report, we describe some of our current prospects and plans to explore and develop those prospects. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect requiring substantial additional seismic data processing and interpretation. It is not possible to predict with certainty whether any particular prospect will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or be economically producible. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in economically producible quantities. We cannot assure you the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified 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 uncertainties, including crude oil and natural gas prices; the availability of capital, drilling rigs, well completion crews, and transportation and processing capacity; costs; drilling results; regulatory approvals; and other factors. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the potential drilling locations we have identified 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. In addition, 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. Low commodity prices, reduced capital spending, lack of available drilling and completion rigs and crews, and numerous other factors, many of which are beyond our control, could result in our failure to establish production on undeveloped acreage, and, 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 represents 57% of our total net undeveloped acreage at December 31, 2017. At that date, we had leases representing 102,258 net acres expiring in 2018, 145,997 net acres expiring in 2019, and 93,664 net acres expiring in 2020. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Our proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2017, approximately 55% of our total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. 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, 2017 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $6.4 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 fund necessary capital expenditures or otherwise, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any
proved undeveloped reserves not developed within this five-year time frame. Such removals have occurred in the past and will likely occur in the future. A removal of such reserves could adversely affect our operations. In 2017, 89 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.
Our business depends on crude oil and natural gas transportation, processing, and refining facilities, most of which are owned by third parties.
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 and refining 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 some 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 would be unable to realize revenue from those wells until other arrangements were made for the sale or delivery of our products and acreage lease terminations could result if production is shut-in for a prolonged period.
The disruption of transportation, processing or refining facilities due to labor disputes, maintenance, civil disturbances, public protests, terrorist attacks, cyber attacks, adverse weather, natural disasters, seismic events, changes in tax and energy policies, federal, state and international regulatory developments, changes in supply and demand, equipment failures or accidents, including pipeline and gathering system ruptures or train derailments, and general economic conditions could negatively impact our ability to achieve 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 prices 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 commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings absent sufficient cash flows.
Our operated crude oil and natural gas production is transported to market centers primarily using pipeline and rail transportation facilities 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. We do not currently own or operate transportation infrastructure; however, compliance with regulations that impact the transportation of crude oil or natural gas could increase our costs of doing business and limit our ability to transport and sell our production at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.
Our business depends on the availability of water and the ability to dispose of waste water from oil and gas activities. Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.
With current technology, water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought), or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection wells.
In addition, concerns have been raised about the potential for seismic events to occur from the use of underground injection wells, a predominant method for disposing of waste water from oil and gas activities. Rules and regulations have been developed in Oklahoma to address these concerns by limiting or eliminating the ability to use disposal wells in certain locations or increasing the cost of disposal. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations. Some states, including states in which we operate, have delayed permit approvals, mandated a reduction in injection volumes, or have shut down or imposed moratoria on the use of injection wells. Regulators in some states, including states in which we operate, are considering additional requirements related to seismicity. For example, in Oklahoma, the Oklahoma Corporation Commission (“OCC”) has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of the state. These rules require disposal well operators, among other things, to conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma has adopted a “traffic light” system wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted.
Compliance with existing or new environmental regulations and permit requirements governing the withdrawal, storage, and use of water necessary for hydraulic fracturing of wells or the disposal of waste water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations 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, including those governing environmental protection, the occupational health and safety aspects of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a description of the laws and regulations that affect us. In order to conduct operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Environmental regulations may restrict the types, quantities and concentration of materials released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenues.
Failure to comply with laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations and litigation. Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
Moreover, our costs of compliance with existing laws could be substantial and may increase, or unforeseen liabilities could be imposed, if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
Climate change legislation or regulations governing the emissions of “greenhouse gases” could result in increased operating costs, limitations in our ability to develop and produce reserves, and reduced demand for the crude oil, natural gas and natural gas liquids we produce.
In response to EPA findings that emissions of carbon dioxide, methane and other greenhouse gases endanger human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act establishing, among other things, Prevention of Significant Deterioration (“PSD”) pre-construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for greenhouse gas emissions are also required to meet “best available control technology” standards established on a case-by-case basis. For further discussion of Title V and PSD concerns, see Part I, Item 1. Business–Regulation of the Crude Oil and Natural Gas Industry–Environmental regulation–Air emissions and climate change. Also see Part I, Item 1. Business–Regulation of the Crude Oil and Natural Gas Industry–Environmental regulation–Environmental protection and natural gas flaring. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Air emissions and climate change for further discussion of the laws and regulations that affect us with respect to climate change initiatives. 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.
Certain previously existing climate-related regulations, such as those related to the control of methane emissions, have been, or are in the process of being, reviewed, suspended, revised, or rescinded in response to President Trump's March 2017 Executive Order. Undoing previously existing regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further climate-related regulation of our industry may stall at the federal level under the March 2017 Executive Order, certain states have pursued additional regulation of our operations related to the emission of greenhouse gases and other states may do so as well. For instance, several state and regional greenhouse gas cap and trade
programs have emerged, while other states have imposed limitations on emissions of methane through equipment control and leak detection and repair requirements.
The implementation of, and compliance with, regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions, install new equipment to reduce emissions of greenhouse gases associated with our operations, or limit our ability to develop and produce our reserves. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the crude oil and natural gas we produce, which could lower the value of our reserves and have a material adverse effect on our business, financial condition, results of operations and cash flows.
Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods or other climatic events. If any such effects were to occur as a result of climate change or otherwise, they could have an adverse effect on our assets and operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays, and an inability to develop existing reserves or to book future reserves.
Hydraulic fracturing is an important and commonly used process in the completion of crude oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the high-pressure injection of water, sand or other proppant and additives into rock formations to stimulate crude oil and natural gas production. In recent years there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and to induce seismic events. As a result, several federal and state regulatory initiatives have emerged that seek to increase the regulatory burden imposed on hydraulic fracturing. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Hydraulic fracturing for a description of the laws and regulations that affect us with respect to hydraulic fracturing.
States in which we operate have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure, and well construction and reclamation 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.
The adoption of any future federal, state or local law or implementing regulation imposing permitting or reporting obligations on, or otherwise limiting, the hydraulic fracturing process, or the discovery of groundwater contamination or other adverse environmental effects directly connected to hydraulic fracturing, could make it more difficult and more expensive to complete crude oil and natural gas wells in low-permeability formations and increase our costs of compliance and doing business, as well as delay, prevent or prohibit the development of natural resources from unconventional formations. In the event regulations are adopted to prohibit or significantly limit the use of hydraulic fracturing in states in which we operate, it would have a material adverse effect on our ability to economically find and develop crude oil and natural gas reserves in our strategic plays. The inability to achieve a satisfactory economic return could cause us to curtail or discontinue our exploration and development plans, which would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Proposed changes to existing laws or regulations or changes in interpretations of laws and regulations under consideration could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.
Changes to existing laws or regulations, new 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 obligations upon us, such as increased reporting or audits. Any of these requirements could result in increased operating costs and could have a material adverse effect on our financial condition and results of operations. If such legislation, regulations or interpretations are adopted, they could result in, among other items, additional restrictions on hydraulic fracturing of wells, restrictions on the disposal of waste water from oil and gas activities, restrictions on emissions of greenhouse gases, modification of equipment utilized in our operations, changes to the calculation of royalty payments, new safety requirements such as those involving rail transportation, and additional regulation of private energy commodity derivative and hedging activities. These and other potential laws, regulations, interpretations and other requirements could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. This, in turn, could have a material adverse effect on our financial condition, results of operations and cash flows.
Certain aspects of the newly enacted federal income tax reform legislation in the United States could adversely affect us.
On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law by President Trump. The Tax Reform Act represents the most significant tax policy change in the United States since 1986 and includes, among others, the following key changes to federal tax law:
Reduces the corporate tax rate from 35% to 21% and eliminates the corporate alternative minimum tax;
Limits the tax deduction for certain net operating loss (NOL) carryforwards to 80% of taxable income for a taxable year, allows NOLs generated in years after December 31, 2017 to be carried forward indefinitely, and repeals NOL carrybacks;
Limits the tax deduction for business interest expense to 30% of adjusted taxable income for a taxable year;
Allows businesses to immediately expense the cost of new investments in certain qualified depreciable assets;
Creates a territorial tax system rather than a worldwide system, which generally allows companies to repatriate future foreign source earnings without incurring additional U.S. taxes;
Subjects foreign earnings on which U.S. income tax is currently deferred to a one-time transition tax; and
Eliminates or reduces certain deductions, exclusions, and credits and adds other provisions that broaden the tax base.
Changes arising from the Tax Reform Act, which are subject to a number of important qualifications and exceptions, generally become effective for tax years beginning after December 31, 2017. Certain of the changes are permanent, while others expire at specified dates. The Tax Reform Act's provisions could have state and local tax implications. While some states automatically adopt federal tax law changes, others conform their laws with federal law on specific dates. States also may choose to decouple from the new federal tax provisions and continue to apply previous law.
Apart from the future benefits to be realized from the reduction in the corporate income tax rate from 35% to 21%, the overall long-term impact of other aspects of the Tax Reform Act is uncertain, and our business, financial condition, results of operations and cash flows could be adversely affected by certain new provisions, particularly the limitations on the tax deductibility of business interest expense and NOLs. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Legislative and Regulatory Developments–Tax Reform Legislation for a forward-looking discussion of the potential impact of the Tax Reform Act.
In previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and gas exploration and production companies. Such proposed changes have included: (i) a repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of deductions for intangible drilling and exploration and development costs; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. These tax deductions currently utilized within our industry are not impacted by the Tax Reform Act. However, no prediction can be made as to whether any legislative changes will be proposed or enacted in the future that could eliminate or defer these or other tax deductions utilized within our industry.
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 to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment 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. Certain of 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. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, securing long-term transportation and processing capacity, marketing hydrocarbons, attracting and retaining quality personnel, and raising additional capital, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, induced seismicity, and greenhouse gas emissions may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and
enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to conduct our business.
Energy conservation measures or initiatives that stimulate demand for alternative forms of energy could reduce the demand for the crude oil and natural gas we produce.
Fuel conservation measures, climate change initiatives, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices could reduce demand for the crude 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.
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, blizzards and ice storms affecting the areas in which we operate, including our corporate headquarters, could have a material adverse effect on our operations or the operations of third party service providers. Such events may result in significant destruction of infrastructure, businesses, and homes and could disrupt the distribution and supply of crude oil and natural gas products in the impacted region. The consequences of such events may include the evacuation of personnel; damage to and disruption of drilling rigs or transportation, processing, storage and refining facilities; the shut-in of production resulting from an inability to transport crude oil or natural gas products to market centers and other factors; an inability to access well sites; destruction of information and communication systems; and the disruption of administrative and management processes, any of which could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations or cash flows.
Regulations under the Dodd-Frank Act regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risk and other risks associated with our business.
From time to time, we may use derivative instruments to manage commodity price risk. In 2010, the U.S. Congress adopted the Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This financial reform legislation includes provisions that require many derivative transactions previously executed over-the-counter to be executed through an exchange and be centrally cleared. In addition, this legislation calls for the imposition of position limits for swaps, including swaps involving physical commodities such as crude oil and natural gas, which have been proposed but have not been finalized. It also establishes minimum margin requirements for uncleared swaps for swap dealers and major swap participants.
If we do not qualify for an end user exemption from the Dodd-Frank requirements, the new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, lead to fewer potential counterparties, impose new recordkeeping and documentation requirements, and increase our exposure to less creditworthy counterparties. Additionally, the proposed position limits may limit our ability to implement price risk management strategies if we are not able to qualify for any exemption from such limits. Further, if we do not qualify for an end user exemption, the margin requirements for uncleared swaps may require us to post collateral, which could adversely affect our available liquidity. If our use of derivatives becomes limited as a result of the regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower crude oil or natural gas prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows.
The loss of senior management or technical personnel could adversely affect our operations.
We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
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, 2017, non-operated properties represented 18% of our estimated proved developed reserves, 6% of our estimated proved undeveloped reserves, and 11% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including compliance with environmental, safety 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 operator 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 financial condition, results of operations and cash flows.
Our revolving credit facility and indentures for our senior notes contain certain covenants and restrictions that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our goals.
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, and merge, consolidate or sell all or substantially all of our assets. Our revolving 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. 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, 2017, our consolidated net debt to total capitalization ratio, as defined, was 0.51 to 1.00. Our total debt would need to independently increase by approximately $5.2 billion above the existing level at December 31, 2017 (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 need to independently decrease by approximately $2.8 billion below the existing level at December 31, 2017 (excluding the after-tax impact of any non-cash impairment charges) to reach the maximum covenant ratio.
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.
The covenants in our revolving credit facility and senior note indentures may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facility 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 of these covenants could result in a default under our revolving credit facility 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 adversely affect our financial condition and results of operations.
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 depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees and business associates, perform compliance reporting and many other activities related to our business. Our business associates, including vendors, service providers, purchasers of our production, and financial institutions, are also 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 may 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. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber attack involving our information systems and related infrastructure, or that of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to:
unauthorized access to or theft of seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;
data corruption or operational disruption of production-related infrastructure could result in a loss of production, or accidental discharge;
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects; and
a cyber attack on third party transportation, processing, storage or refining facilities could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues.
These events 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 financial condition, results of operations or cash flows.
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. 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.
Increases in interest rates could adversely affect our business.
The U.S. Federal Reserve increased the benchmark federal funds interest rate on three separate occasions in 2017 and is forecasting additional increases in 2018 and 2019. Our business and operating results can be adversely affected by increases in interest rates, the availability, terms of and cost of capital, or downgrades or other negative rating actions with respect to our credit rating. These factors could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our financial condition and results of operations.
The inability of joint interest owners, derivative counterparties, 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 ($672 million in receivables at December 31, 2017); our joint interest and other receivables ($427 million at December 31, 2017); and counterparty credit risk associated with our derivative instrument receivables ($3 million at December 31, 2017).
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.
We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with significant customers. The two largest purchasers of our crude oil and natural gas during the year ended December 31, 2017 accounted for approximately 11% and 11%, respectively, of our total crude oil and natural gas revenues for the year. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Additionally, our use of derivative instruments involves the risk that our counterparties will be unable to meet their obligations.
Finally, we rely on oilfield 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 financial condition, results of operations and cash flows.
Our derivative activities could result in financial losses or reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in commodity prices, from time to time we may enter into derivative instruments for a portion of our production. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments for a summary of our commodity derivative positions as of December 31, 2017. We do not designate any of our derivative instruments as hedges for accounting purposes and we record all derivatives on our balance sheet at fair value. Changes in the fair value of our derivatives are recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in commodity prices and resulting changes in the fair value of our derivatives.
Derivative instruments expose us to the risk of financial loss in certain circumstances, including when:
production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contractual obligations; or
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, our derivative arrangements limit the benefit we would receive from increases in commodity prices. Our decision on the quantity and price at which we choose to hedge our future production, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to hedge future production if the pricing environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to liquidate 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.
We have hedged the majority of our forecasted 2018 natural gas production. Our future crude oil production is currently unhedged and directly exposed to continued volatility in market prices, whether favorable or unfavorable.
Our Chairman and Chief Executive Officer beneficially owns approximately 76% of our outstanding common stock, giving him influence and control in corporate transactions and other matters, including a sale of our Company.
As of December 31, 2017, Harold G. Hamm, our Chairman and Chief Executive Officer, beneficially owned approximately 76% of our outstanding common shares. As a result, Mr. Hamm has control over our Company and will continue to be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other shareholders, the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. Therefore, Mr. Hamm could cause, delay or prevent a change of control of our Company. The interests of Mr. Hamm may not coincide with the interests of other holders of our common stock.
We have historically entered into, and may enter into, transactions from time to time with companies affiliated with Mr. Hamm if, after an independent review by our Audit Committee or by the independent members of our Board of Directors, it is determined such transactions are in the Company’s best interests and are on terms no less favorable to us than could be achieved with an unaffiliated third party. These transactions may result in conflicts of interest between Mr. Hamm’s affiliated companies and us.
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.
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, 2021, non-operated properties represented 14% of our estimated proved developed reserves, 7% of our estimated proved undeveloped reserves, and 11% 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 successful acquisition of producingoil and gas properties requires an assessment of several factors, including but not limited to:
•reservoir modeling and evaluation of recoverable reserves;
•future crude oil and natural gas prices and location and quality differentials;
•the quality of the title to acquired properties;
•the ability to access future drilling locations;
•availability and cost of gathering, processing, and transportation facilities;
•availability and cost of drilling and completion equipment and of skilled personnel;
•future development costs,and operating costs and property taxes; and
potential environmental and other liabilities.liabilities; and
•regulatory, permitting and similar matters.
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
of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Significant acquisitions and other strategic transactions may involve other risks that may impact our business, including:
•diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
•the challenge and cost of integrating acquired assets and operations with our preexisting assets and operations while carrying on our ongoing business; and
•the failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.
As a result of our 2021 property acquisitions in the Permian Basin and Powder River Basin, the size and geographic footprint of our business has increased, and 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 these acquisitions will complement our business strategies by delivering enhanced free cash flows, corporate returns, and shareholder value, 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 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. The occurrence of any of the matters described above could have an adverse impact on our business, financial condition, results of operations and cash flows.
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, 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 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 climatic events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Severe climatic 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. Climate changes could result in increased frequency and severity of these climatic events, as well as chronic shifts in temperature and precipitation patterns. The consequences of such events may include the evacuation of personnel; damage to and disruption of production equipment, drilling rigs, or gathering, transportation, processing, storage, refining, and export facilities; delivery stoppages by third party vendors upon whom we rely upon for goods and services; the shut-in of production resulting from an inability to transport crude oil or natural gas products to market centers and other factors; an inability to access well sites; destruction of information and communication systems; and the disruption of administrative and management processes, any of which could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations or cash flows. Our planning for normal climatic variation, 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 our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle Eastabroad and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that infrastructure we rely on could be a direct target or an indirect casualty of an act of terrorism, and, in turn,terrorism. Any of these events could materially and adversely affect our business and results of operations.
Financial Risks
Our derivative activities could result in financial losses or reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in commodity prices, from time to time we may enter into derivative instruments for a potentially significant portion of our production. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 6. Derivative Instruments for a summary of our commodity derivative positions as of December 31, 2021. Additionally, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Derivative Instruments for a summary of additional derivative instruments entered into subsequent to December 31, 2021. We do not designate our derivative instruments as hedges for accounting purposes and we record all derivatives on our balance sheet at fair value. Changes in the fair value of derivatives are recognized in earnings. Accordingly, our earnings may fluctuate materially as a result of changes in commodity prices and resulting changes in the fair value of any outstanding derivatives.
Derivative instruments expose us to the risk of financial loss in certain circumstances, including when:
•production is less than the volume covered by the derivative instruments;
•the counterparty to the derivative instrument defaults on its contractual obligations; or
•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, derivative arrangements limit the benefit we would otherwise receive from increases in commodity prices. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to hedge future production if the pricing environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to settle derivative positions prior to the expiration of their contractual maturities.
Our revolving credit facility and indentures for our senior notes contain certain covenants and restrictions that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our goals.
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, and merge, consolidate or sell all or substantially all of our assets. Our revolving 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. 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, 2021, we had $500 million of outstanding borrowings on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.43.
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.
The covenants in our revolving credit facility and senior note indentures may restrict our ability to expand or pursue our business strategies. Our ability to comply with the provisions of our revolving credit facility 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 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 ($1.1 billion in receivables at December 31, 2021) and our joint interest and other receivables ($279 million at December 31, 2021). 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 those 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, and employees and labor relations. Following is a discussion of certain significant laws, rules and regulations that affect us in these areas in which we operate. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion of the regulations that affect us.
Taxation of oil and gas activities—President Biden's administration is pursuing 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. The passage of such legislation or any other similar change in U.S. federal income tax law could adversely affect our business, financial condition, results of operations and cash flows.
Dodd-Frank Act derivative regulations—In 2010, the U.S. Congress adopted the Dodd-Frank Act, which, among other provisions, established federal oversight and regulation of the over-the-counter derivatives market. If we do not qualify for an end user exemption from the Dodd-Frank Act requirements, the regulations could increase the cost of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, lead to fewer potential counterparties, and increase our exposure to less creditworthy counterparties, any of which could limit our desire and ability to implement commodity price risk management strategies. Certain other regulations, including regulations related to capital requirements, which are yet to be implemented, may have an effect that results in the reduction of the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to us. If our use of derivatives becomes limited as a result of the regulations, our results of operations may become more volatile and our cash flows may be less predictable. Aspects of the Dodd-Frank rulemaking have been finalized in certain areas, but other areas have not been finalized or implemented and the ultimate effect of these regulations on our business remains uncertain.
Failure to comply with the above and other laws and regulations 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, including those in response to the January 2021 change in U.S. presidential administrations and shift in control of Congress, 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 climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the demand 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 generation devices may create new competitive conditions that result in reduced demand for the crude 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 commodities we produce which could lead to increased volatility in commodity prices. 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 more of these developments could have an adverse effect on our assets and operations.
We are involved in legal proceedings that could result in substantial liabilities.
Like other similarly-situated oil and gas companies, we are, from time to time, involved in various legal proceedings in the ordinary course of business 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. The outcome of such legal matters often cannot be predicted with certainty. We vigorously defend ourselves in all such matters. However, if our efforts to defend ourselves are not successful, it is possible the outcome of one or more such proceedings could result in substantial liability, penalties, sanctions, judgments, consent decrees, or orders requiring a change in our business practices, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Judgments and estimates to determine accruals related to legal and other proceedings could change from period to period, and such changes could be material.
Increasing scrutiny on environmental, social, and corporate governance matters may impact our business.
Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. ESG standards are evolving and if we are 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, financial condition, and/or stock price could be 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 stock price, our ability to recruit necessary talent, and our access to capital markets.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings and, in fact, different standards focus, to varying degrees, on different attributes of environmental, social, and corporate governance matters. This disparity between the “standards” may result in investors focusing on inadequate or improper metrics which may lead to a misperception of a company and its ESG practices. Conversely, pressures to create more uniformity among these “standards” may result in a skewed and potentially misplaced focus on certain factors over other, equally valuable factors. For example, of the 17 United Nations Sustainability Goals, the vast majority fall within the societal component, but many sustainability “standards” provide little weight to these goals, instead emphasizing the environmental component. Nonetheless, the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. ESG ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers, and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of our stock from consideration by certain investment funds, engagement by investors seeking to improve such scores, and a negative perception of our operations by certain investors.
Risks Related to our Corporate Structure
Our Chairman of the Board and members of his family beneficially own approximately 82% of our outstanding common stock, giving them influence and control in corporate transactions and other matters, including a sale of our Company.
As of December 31, 2021, Harold G. Hamm, our Chairman of the Board, and members of his family, beneficially owned approximately 82% of our outstanding common shares. As a result, Mr. Hamm and his family have control over our Company and will continue to be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other shareholders, the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. Therefore, Mr. Hamm and his family could cause, delay or prevent a change of control of our Company. The interests of Mr. Hamm and his family may not coincide with the interests of other holders of our common stock.
We have historically entered into, and may enter into, transactions from time to time with companies or persons affiliated with Mr. Hamm and his family, if, after an independent review by our Audit Committee or by the independent members of our Board of Directors, it is determined such transactions are in the Company’s best interests and are on terms no less favorable to us than could be achieved with an unaffiliated third party. These transactions may result in conflicts of interest between Mr. Hamm’s affiliated parties and us.
Item 1B. Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2017.2021.
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.
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Item 3. | Item 3. Legal Proceedings |
See Note 10. Commitments and Contingencies–Litigation in Part II, Item 8. Financial Statements and Supplementary Data–Notes to Consolidated Financial Statements for a discussion of the legal matter involving the Company, Billy J. Strack and Daniela A. Renner, which is incorporated herein by reference.
We are involved in various 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, we do not expect them to have received Noticesa material effect on our financial condition, results of Violation from the North Dakota Department of Health (“NDDH”) alleging violations of the state’s air quality and water pollution control laws and rules. We exchanged information and engaged in discussions with NDDH aimed at resolving the allegations and anticipate further discussions and exchanges. Resolution of the allegations may result in monetary sanctions of more than $100,000.operations or cash flows.
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Item 4. | Mine Safety Disclosures |
Item 4. Mine Safety Disclosures
Not applicable.
Part II
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Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange and trades under the symbol “CLR.” 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.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. As of January 31, 2018,February 2, 2022, the number of record holders of our common stock was 1,146. Management believes,1,269. On February 2, 2022, after inquiry, management believes that the number of beneficial owners of our common stock is approximately 64,400.79,854. On January 31, 2018,February 2, 2022, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $55.53$55.08 per share.
In May 2019, our Board of Directors approved the initiation of a dividend payment program. On February 9, 2022, the Company declared a quarterly cash dividend of $0.23 per share on its outstanding common stock, which will be paid on March 4, 2022 to shareholders of record as of February 22, 2022. The Company intends to continue paying a quarterly dividend; however, any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our future earnings, financial condition, cash flows, capital requirements, levels of indebtedness, prevailing business conditions and other considerations our Board of Directors may deem relevant.
The following table summarizes ourprovides information about purchases of our common stock during the quarter ended December 31, 2017:2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
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, 2021 to October 31, 2021 | | | | | | | | |
Repurchases for tax withholdings (2) | | 11,288 | | | $ | 52.13 | | | — | | | $ | — | |
November 1, 2021 to November 30, 2021 | | | | | | | | |
Repurchases for tax withholdings (2) | | 41,154 | | | $ | 49.36 | | | — | | | $ | — | |
Share repurchase program (1) | | 1,102,682 | | | $ | 46.30 | | | 1,102,682 | | | $ | 566.5 | |
Purchases by principal shareholder (3) | | 108,500 | | | $ | 47.69 | | | — | | | $ | — | |
December 1, 2021 to December 31, 2021 | | | | | | | | |
Share repurchase program (1) | | 179,820 | | | $ | 42.33 | | | 179,820 | | | $ | 558.9 | |
Purchases by principal shareholder (3) | | 367,020 | | | $ | 43.82 | | | — | | | $ | — | |
Total for the quarter | | 1,810,464 | | | $ | 45.59 | | | 1,282,502 | | | |
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| | | | | | | | | | | | | |
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 |
| | — |
| | — |
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(1)In May 2019 our Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019 at times and levels deemed appropriate by management. The program was announced on June 3, 2019 and does not have a set expiration date. As of December 31, 2021, the total dollar value of shares that may yet be purchased under the original program totaled $558.9 million. On February 8, 2022, our Board of Directors approved an increase in the size of the share repurchase program to $1.5 billion, inclusive of cumulative amounts repurchased to date. As of the date of this filing, we have repurchased a cumulative $441.1 million of our common stock. Accordingly, the total dollar value of shares that may yet be purchased now totals approximately $1.06 billion under the modified program. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board of Directors at any time.(2)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 our common stock on the date the restrictions lapsed on such shares.
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(1) | In connection with restricted stock grants under the Company’s 2013 Long-Term Incentive Plan (“2013 Plan”), we adopted a policy that enables employees to surrender shares to cover their tax liability. Shares indicated as having been purchased in the table above represent shares surrendered by employees to cover tax liabilities. We paid the associated taxes to the applicable taxing authorities. |
| |
(2) | The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares. |
(3)Represents shares of our common stock purchased in open market transactions by Harold G. Hamm, our Chairman of the Board and principal shareholder.
Equity Compensation Plan Information
The following table sets forth the information as of December 31, 20172021 relating to equity compensation plans:
|
| | | | | | | | | | | | | | | | | | | |
| | Number of Shares
to be Issued Upon
Exercise of
Outstanding
Options | | Weighted-Average
Exercise Price of
Outstanding Options | | Remaining Shares
Available for Future
Issuance Under Equity
Compensation Plans (1) |
Equity Compensation Plans Approved by Shareholders | | — |
| | — |
| | 14,538,540 | 8,492,645 |
Equity Compensation Plans Not Approved by Shareholders | | — |
| | — |
| | — |
|
| |
(1) | Represents the remaining shares available for issuance under the 2013 Plan. |
(1)Represents the remaining shares available for issuance under the 2013 Plan.
Performance Graph
The following graph compares our common stock performance with the performance of the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Dow Jones US Oil and Gas Index (“Dow Jones US O&G Index”) for the period of December 31, 20122016 through December 31, 2017.2021. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, 20122016 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.
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Item 6. | Selected Financial Data |
This section presents selected consolidated financial data for the years ended December 31, 2013 through 2017. The selected financial data presented below is not intended to replace our consolidated financial statements.
The following consolidated financial data has been derived from our audited consolidated financial statements for such periods. You should read the following selected financial data in connection with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and related notes included elsewhere in this report. The selected consolidated results are not necessarily indicative of results to be expected in future periods.
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| | | | | | | | | | | | | | | | | | | | |
| | 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 6. Reserved
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(1) | Crude oil and natural gas derivative instruments are not designated as hedges for accounting purposes and, therefore, changes in the fair value of the instruments are shown separately from crude oil and natural gas sales. The amounts above include non-cash mark-to-market gains (losses) on crude oil and natural gas derivatives of $62.1 million, ($160.7) million, $21.5 million, $174.4 million, and ($130.2) million for the years ended December 31, 2017, 2016, 2015, 2014, and 2013, respectively. Additionally, 2014 includes $433 million of gains recognized from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities initially scheduled through December 2016. |
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(2) | Results for 2017 reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Cuts and Jobs Act in December 2017, which resulted in a one-time increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share). See Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies, which resulted in an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share).
|
| |
(3) | At various times, we have stored crude oil due to pipeline line fill requirements, low commodity prices, or marketing disruptions or we have sold crude oil from inventory. These actions result in differences between our produced and sold crude oil volumes. |
| |
(4) | Average sales prices and average costs per unit have been computed using sales volumes and exclude any effect of derivative transactions. |
| |
(5) | General and administrative (“G&A”) expenses ($/Boe) include non-cash equity compensation expenses of $0.52 per Boe, $0.61 per Boe, $0.64 per Boe, $0.86 per Boe, and $0.80 per Boe for the years ended December 31, 2017, 2016, 2015, 2014, and 2013, respectively. |
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ITEM 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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 Part I, Item 1. Business—Crude Oil and Natural Gas Operations.below.
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. Additionally, we pursue the acquisition and management of perpetually owned minerals located in our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas and expect this to continue in the future. Our operationsWe are primarily focused on explorationthe largest leaseholder and development activitiesthe largest producer in the Bakken field of North Dakota and Montana andMontana. We also have significant positions in the SCOOP and STACK areas of Oklahoma.
Business Environmentplays in Oklahoma and Outlook
Continental marked its 50th anniversaryrecently acquired positions in the oilPermian Basin of Texas and gas business in 2017. Powder River Basin of Wyoming.Our leadership team has significant experience withcommon stock trades on the New York Stock Exchange under the symbol “CLR” and our corporate internet website is www.clr.com.
2021 Highlights
Financial and operating in challenging commodity price environments. Commodity prices remained volatile during the year, but generally increasedhighlights for 2021 are summarized below. Our 2021 results underscore our continued focus on average in 2017 relative 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 manage the ongoing challenges and price volatility facing our industry.
For 2018, our primary business strategies will focus on:
Balancing strong production growth with freemaximizing cash flow generation;generation, maintaining low-cost capital efficient operations in an environmentally responsible manner, achieving consistent asset performance, and delivering capital and corporate returns to shareholders.
Enhancing cash flows and return on capital employed through improvements•Generated $1.25 billion in operating efficiencies, technical innovations, and optimized completion methods;
Continuing to exercise disciplined capital spending to maintain financial flexibility and ample liquidity; and
Improving 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, we havethe fourth quarter, bringing year-to-date operating cash flows to a Company record $3.97 billion;
•Completed strategic acquisitions to expand our operations into the Permian Basin for cash consideration of $3.06 billion and the Powder River Basin for cash consideration totaling $453 million;
•Sequentially increased our planned non-acquisition capital spending for 2018quarterly fixed dividend throughout year, paying $166 million of dividends in 2021 with an additional $82 million of declared dividends 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 areasbe paid in the North Dakotafirst quarter of 2022;
•Repurchased 3.2 million shares of common stock in 2021 under our share repurchase program at an aggregate cost of $124 million; and
•Continued to maintain low cost operations with production expenses averaging $3.38 per Boe for 2021.
With our acquisitions in the Permian Basin and Powder River Basin in 2021 we now have substantial strategic positions in four leading basins in the United States, providing our Company and shareholders with enhanced geologic and geographic diversity and commodity optionality. We believe these transactions will be accretive on financial metrics and will complement our existing deep portfolio of assets in the Bakken and SCOOP Springer plays.Oklahoma. We expect to fund our budgeted spending usingenhanced cash flows from operations. We may adjustthe acquisitions will provide continued support for additional returns to shareholders via debt reduction, dividend increases, share repurchases, and increased returns on capital employed. See Part I, Item 1. Business—Acquisition Activities and Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions for additional information on the acquisitions.
Financial and Operating Metrics
Our operating results for 2020 were severely impacted by the economic effects from the COVID-19 pandemic on crude oil demand and prices. In response to the significant reduction in crude oil prices during 2020, we curtailed approximately 55% of our pace of drillingoperated crude oil production and development as 2018 market conditions evolve.
2017 Highlights
Productionassociated natural gas in the 2020 second quarter and significantly reduced our capital spending. In July 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online in September 2020. These actions resulted in material reductions in our production, revenues, and cash flows for 2020.
Crude oil and natural gas prices have increased significantly in 2021 compared to 2020 levels in response to the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals. The increase in commodity prices and resumption of our operations resulted in significantly improved operating results in 2021 compared to 2020 as further described below.
The following table contains financial and operating highlights for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
The previously described Permian Basin acquisition closed on December 21, 2021 and thus had a limited impact on fourth quarter and full year 2021 operating results given our short duration of ownership. The acquired Permian assets contributed 460 MBoe of production averaged 242,637(42,000 Boe per day in 2017, an increaseon average of 12% comparedwhich 78% was oil), $29.4 million of revenues, and $14.1 million ($0.04 per basic and diluted share) of net income to 2016.our consolidated results during the period of ownership from December 21, 2021 to December 31, 2021.
Total production | | | | | | | | | | | | | | | | | | | | |
| | Year ended December 31, |
| | 2021 | | 2020 | | 2019 |
Average daily production: | | | | | | |
Crude oil (Bbl per day) | | 160,647 | | | 160,505 | | | 197,991 | |
Natural gas (Mcf per day) | | 1,014,000 | | | 837,509 | | | 854,424 | |
Crude oil equivalents (Boe per day) | | 329,647 | | | 300,090 | | | 340,395 | |
Average net sales prices: (1) | | | | | | |
Crude oil ($/Bbl) | | $ | 64.06 | | | $ | 34.71 | | | $ | 51.82 | |
Natural gas ($/Mcf) | | $ | 4.88 | | | $ | 1.04 | | | $ | 1.77 | |
Crude oil equivalents ($/Boe) | | $ | 46.24 | | | $ | 21.47 | | | $ | 34.56 | |
Crude oil net sales price discount to NYMEX ($/Bbl) | | $ | (4.00) | | | $ | (5.80) | | | $ | (5.15) | |
Natural gas net sales price premium (discount) to NYMEX ($/Mcf) | | $ | 1.00 | | | $ | (1.10) | | | $ | (0.86) | |
Production expenses ($/Boe) | | $ | 3.38 | | | $ | 3.27 | | | $ | 3.58 | |
Production taxes (% of net crude oil and natural gas sales) | | 7.3 | % | | 8.2 | % | | 8.3 | % |
DD&A ($/Boe) | | $ | 15.76 | | | $ | 17.12 | | | $ | 16.25 | |
Total general and administrative expenses ($/Boe) | | $ | 1.94 | | | $ | 1.79 | | | $ | 1.57 | |
(1) See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.
Results of Operations
The following table presents selected financial and operating information for the fourth quarter of 2017 averaged 286,985 Boe per day, an increase of 18%periods presented.
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
In thousands, except sales price data | | 2021 | | 2020 | | 2019 |
Crude oil and natural gas sales | | $ | 5,793,741 | | | $ | 2,555,434 | | | $ | 4,514,389 | |
Gain (loss) on derivative instruments, net | | (128,864) | | | (14,658) | | | 49,083 | |
Crude oil and natural gas service operations | | 54,441 | | | 45,694 | | | 68,475 | |
Total revenues | | 5,719,318 | | | 2,586,470 | | | 4,631,947 | |
Operating costs and expenses | | (3,257,638) | | | (3,140,362) | | | (3,374,535) | |
Other expenses, net | | (275,542) | | | (220,859) | | | (270,250) | |
Income (loss) before income taxes | | 2,186,138 | | | (774,751) | | | 987,162 | |
(Provision) benefit for income taxes | | (519,730) | | | 169,190 | | | (212,689) | |
Net income (loss) | | 1,666,408 | | | (605,561) | | | 774,473 | |
Net income (loss) attributable to noncontrolling interests | | 5,440 | | | (8,692) | | | (1,168) | |
Net income (loss) attributable to Continental Resources | | $ | 1,660,968 | | | $ | (596,869) | | | $ | 775,641 | |
Diluted net income (loss) per share attributable to Continental Resources | | $ | 4.56 | | | $ | (1.65) | | | $ | 2.08 | |
Production volumes: | | | | | | |
Crude oil (MBbl) | | 58,636 | | | 58,745 | | | 72,267 | |
Natural gas (MMcf) | | 370,110 | | | 306,528 | | | 311,865 | |
Crude oil equivalents (MBoe) | | 120,321 | | | 109,833 | | | 124,244 | |
Sales volumes: | | | | | | |
Crude oil (MBbl) | | 58,757 | | | 58,793 | | | 72,136 | |
Natural gas (MMcf) | | 370,110 | | | 306,528 | | | 311,865 | |
Crude oil equivalents (MBoe) | | 120,442 | | | 109,881 | | | 124,113 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
Year ended December 31, 2021 compared to the third quarteryear ended December 31, 2020
Below is a discussion of 2017 and 37% higher than the fourth quarterchanges in our results of 2016.
Average daily crude oil production increased 8% in 2017operations for 2021 compared to 2016 while average daily natural gas production increased 17%.
Crude oil represented 57%2020. A discussion of changes in our results of operations for 2020 compared to 2019 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2017 production compared to 59% for 2016. Crude oil represented 59% of our productionForm 10-K for the fourth quarter of 2017 compared to 58% foryear ended December 31, 2020 as filed with the third quarter of 2017 and 55% for the fourth quarter of 2016.SEC on February 16, 2021.
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 | | 2021 | | 2020 | | % Change | | 2021 | | 2020 | | % Change |
Bakken | | 175,585 | | | 183,141 | | | (4 | %) | | 169,636 | | | 158,604 | | | 7 | % |
Oklahoma | | 146,131 | | | 149,341 | | | (2 | %) | | 147,249 | | | 134,506 | | | 9 | % |
| | | | | | | | | | | | |
Powder River Basin | | 7,189 | | | — | | | — | % | | 5,161 | | | — | | | — | % |
Permian Basin (1) | | 4,997 | | | — | | | — | % | | 1,260 | | | — | | | — | % |
All other | | 6,266 | | | 6,825 | | | (8 | %) | | 6,341 | | | 6,980 | | | (9 | %) |
Total | | 340,168 | | | 339,307 | | | — | % | | 329,647 | | | 300,090 | | | 10 | % |
|
| | | | | | | | | | | | | | | | | | |
| | 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 | % |
Revenues
Crude oil and natural gas revenues totaled $2.98 billion for 2017, a 47% increase compared to 2016 driven by a 32% increase in realized commodity prices coupled with a 12% increase in total sales volumes.
Crude oil and natural gas revenues totaled $1.02 billion for the 2017 fourth quarter, a 44% increase from the 2017 third quarter and 72% higher than the 2016 fourth quarter, reflecting an increase in well completion activities and improvement in commodity prices and price realizations in late 2017. Total sales volumes for the 2017 fourth quarter increased 20% and 38% and realized commodity prices increased 20% and 25% compared to the 2017 third quarter and 2016 fourth quarter, respectively.
Proved reserves
At December 31, 2017, our proved reserves totaled 1,331 MMBoe, an increase(1)The presentation of 4% from proved reserves of 1,275 MMBoe at December 31, 2016.
Extensions and discoveries from our drilling and completion activities added 240 MMBoe of proved reserves in 2017 and upward reserve revisions due to improved commodity prices increased reserves by 42 MMBoe. These increases were partially offset by 89 MMBoe ofaverage daily production represents production during the period from the closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over the respective fourth quarter and full year and net downward reserve revisions totaling 124 MMBoe resulting from changes in drilling plans and other factors.
The following table summarizesperiods. At the changes intime of closing, our proved reserves by major operating area in 2017:
|
| | | | | | | | | | | | | | | | | | |
| | 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 | % |
Operating cash flows
Cash flows from operating activities totaled $2.08 billion for 2017, an increase of 85% compared to $1.13 billion for 2016, reflecting an increase in sales volumes and improvement in commodity prices and price realizations in 2017.
Capital expenditures and drilling activity
Full year 2017 non-acquisition capital expenditures totaledPermian properties produced on average approximately $2.00 billion compared to $1.07 billion for 2016, reflecting our planned increase in spending for 2017 in response to improved commodity prices.
In 2017 we participated in the drilling and completion of 608 gross (214 net) wells compared to 365 gross (92 net) wells in 2016.
2017 property dispositions
In September 2017 we sold non-strategic properties in the Arkoma Woodford area of Oklahoma for cash proceeds of $65.3 million. The sale included approximately 26,000 net acres of leasehold and producing properties with production totaling
approximately 1,70042,000 Boe per day. In connection with the transaction, we recognized a pre-tax loss of $3.5 million for the year ended December 31, 2017.
In September 2017, we reached an agreement to sell non-core leasehold in the STACK play in Blaine County, Oklahoma for cash proceeds totaling $63.5 million. A portion of the transaction closed in September 2017, resulting in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gainday based on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time we received the remaining $59.9 million of proceeds and recognized an additional pre-tax gain of approximately $53.6 million, which is reflected in fourth quarter 2017 results.
In September 2017, we sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.2 million pre-tax gain for the year ended December 31, 2017 associated with the transaction.
Debt and liquidity
Total debt decreased $226 million, or 3%, to $6.35 billion at December 31, 2017 compared to $6.58 billion at year-end 2016.
In December 2017 we issued $1.0 billion of 4.375% Senior Notes due 2028 (“2028 Notes”) and received total net proceeds of $990 million after deducting the initial purchasers’ fees. We used the proceeds from the offering to repay in full and terminate our $500 million term loan due November 4, 2018 and to repay a portion of the borrowings outstanding under our revolving credit facility, thereby resulting in enhanced liquidity.
At December 31, 2017, we had $43.9 million of cash and cash equivalents and $2.56 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had $188 million of credit facility borrowings at December 31, 2017 compared to $938 million at September 30, 2017 and $905 million at December 31, 2016. At January 31, 2018, outstanding credit facility borrowings decreased further to $93 million, leaving approximately $2.65 billion of borrowing availability at that date.
Impact of income tax reform legislation
In December 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, we remeasured our deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share) recognized in the 2017 fourth quarter. See the subsequent section titled Legislative and Regulatory Developments–Tax Reform Legislation and Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income Taxes for further discussion of the Tax Reform Act.
Litigation settlement
On February 16, 2018, we reached a settlement in connection with the case filed in November 2010 in the District Court of Blaine County by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. Under the settlement, if approved by the court, we will make payments and incur costs associated with the settlement of approximately $59.6 million. We have 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, which resulted in an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share). See Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies for further discussion.
Financial and operating highlights
We use a variety of financial and operating measures to assess our performance. Among these measures are:
Volumes of crude oil and natural gas produced;
Crude oil and natural gas price differentials relative to NYMEX benchmark prices; and
Per unit operating and administrative costs.
The following table contains financial and operating highlights for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
|
| | | | | | | | | | | | |
| | Year ended December 31, |
| | 2017 | | 2016 | | 2015 |
Average daily production: | | | | | | |
Crude oil (Bbl per day) | | 138,455 |
| | 128,005 |
| | 146,622 |
|
Natural gas (Mcf per day) | | 625,093 |
| | 533,442 |
| | 450,558 |
|
Crude oil equivalents (Boe per day) | | 242,637 |
| | 216,912 |
| | 221,715 |
|
Average sales prices: | | | | | | |
Crude oil ($/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 |
|
Results of Operations
The following table presents selected financial and operating information for the periods presented.
|
| | | | | | | | | | | | |
| | 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 |
|
| |
(1) | Net of gain on sale of assets of $55.1 million, $304.5 million and $23.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. Additionally, the year 2017 includes the aforementioned $59.6 million loss accrual recognized in conjunction with a litigation settlement. |
| |
(2) | The year 2016 includes a loss on extinguishment of debt of $26.1 million related to the November 2016 redemptions of our $200 million of 7.375% Senior Notes due 2020 and $400 million of 7.125% Senior Notes due 2021. |
| |
(3) | The year 2017 reflects the remeasurement of our deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017, which resulted in a one-time decrease in income tax expense via the recognition of an income tax benefit totaling approximately $713.7 million. |
Year ended December 31, 2017 compared to the year ended December 31, 2016
Productiontwo-stream reporting.
The following tables reflect our production by product and region for the periods presented.
| | | | Year Ended December 31, | | Volume increase | | Volume percent increase | | | Year Ended December 31, | | Volume increase (decrease) | | Volume percent increase (decrease) |
| | 2017 | | 2016 | | | | 2021 | | 2020 | |
| | Volume | | Percent | | Volume | | Percent | | | | Volume | | Percent | | Volume | | Percent | |
Crude oil (MBbl) | | 50,536 |
| | 57 | % | | 46,850 |
| | 59 | % | | 3,686 |
| | 8 | % | Crude oil (MBbl) | | 58,636 | | | 49 | % | | 58,745 | | | 53 | % | | (109) | | | — | % |
Natural gas (MMcf) | | 228,159 |
| | 43 | % | | 195,240 |
| | 41 | % | | 32,919 |
| | 17 | % | Natural gas (MMcf) | | 370,110 | | | 51 | % | | 306,528 | | | 47 | % | | 63,582 | | | 21 | % |
Total (MBoe) | | 88,562 |
| | 100 | % | | 79,390 |
| | 100 | % | | 9,172 |
| | 12 | % | Total (MBoe) | | 120,321 | | | 100 | % | | 109,833 | | | 100 | % | | 10,488 | | | 10 | % |
Our revenues consist of sales of crude oil and natural gas, 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.