PART I
Except as noted, in this Annual Report on Form 10-K, we refer to Diamondback, together with its consolidated subsidiaries, as “we,” “us,” “our,” or “the Company”. This reportAnnual Report includes certain terms commonly used in the oil and natural gas industry, which are defined above in the “Glossary of Oil and Natural Gas Terms.”
ITEM 1.ITEMS 1 and 2. BUSINESS AND PROPERTIES
Overview
We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators.
We beganreport operations in December 2007 with our acquisition of 4,174 net acres inone reportable segment, the Permian Basin. At December 31, 2017, our total acreage position in the Permian Basin was approximately 246,012 gross (206,660 net) acres. In addition, we, through our subsidiary Viper Energy Partners LP, or Viper, own mineral interests underlying approximately 247,602 gross acres, 43,843 net acres and 9,570 net royalty acres primarily in Midland County, Texas in the Permian Basin. Approximately 36% of these net royalty acres are operated by us. We own Viper Energy Partners GP LLC, the general partner of Viper, which we refer to as the general partner, and we own approximately 64% of the limited partner interest in Viper.upstream segment.
Our activities are primarily focused on horizontal development of the Spraberry and Wolfcamp formations of the Midland Basin and the Wolfcamp and Bone Spring formations of the Delaware Basin, both of which are part of the larger Permian Basin in West Texas and New Mexico. The Permian Basin isThese formations are characterized by a high concentration of oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates.
At December 31, 2023, our total acreage position in the Permian Basin was approximately 607,877 gross (493,769 net) acres, which consisted primarily of 428,324 gross (349,707 net) acres in the Midland Basin and 174,828 gross (143,742 net) acres in the Delaware Basin.
In addition, our publicly traded subsidiary Viper Energy, Inc., which we refer to as Viper, owns mineral interests primarily in the Permian Basin. We own approximately 56% of Viper’s outstanding shares of common stock.
As of December 31, 2017,2023, our estimated proved oil and natural gas reserves were 335,3522,177,761 MBOE (which includes estimated reserves of 38,246179,249 MBOE attributable to the mineral interests owned by Viper), based on reserve reports prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers. Of these reserves,. As of December 31, 2023, approximately 62.2%69% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 168802 gross (142(719 net) horizontal well locations in which we have a working interest, and nine horizontal wells in which we own only a mineral interest through our subsidiary, Viper.interest. As of December 31, 2017,2023, our estimated proved reserves were approximately 70%53% oil, 14%23% natural gas liquids and 16%24% natural gas.gas liquids.
BasedSignificant Recent Acquisitions and Divestitures
GRP Acquisition
On November 1, 2023, Viper acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP and affiliates of Warwick Capital Partners and GRP Energy Capital (collectively, “GRP”), pursuant to a definitive purchase and sale agreement in exchange for approximately 9.02 million Viper common units and $760 million in cash consideration, including transaction costs and subject to customary post-closing adjustments (the “GRP Acquisition”). The mineral and royalty interests acquired included 4,600 net royalty acres in the Permian Basin, plus an additional 2,700 net royalty acres in other major basins.
Deep Blue Formation and Divestiture of Deep Blue Water Assets
On September 1, 2023, we closed on a joint venture agreement with Five Point Energy LLC (“Five Point”) to form Deep Blue Midland Basin LLC (“Deep Blue”). At closing, we contributed certain treated water, fresh water and saltwater disposal assets (the “Deep Blue Water Assets”) with a net carrying value of $692 million in exchange for $516 million in cash consideration and a 30% equity ownership and voting interest in Deep Blue and certain contingent consideration.
Lario Acquisition
On January 31, 2023, we closed on the acquisition of all leasehold interests and related assets of Lario Permian, LLC, a wholly owned subsidiary of Lario Oil and Gas Company, and certain associated sellers (collectively “Lario”), which included approximately 25,000 gross (16,000 net) acres in the Midland Basin and certain related oil and gas assets (the “Lario Acquisition”) in exchange for 4.33 million shares of our evaluationcommon stock and $814 million in cash consideration, including certain customary post-closing adjustments.
Pending Endeavor Acquisition
On February 11, 2024, we currently haveentered into an Agreement and Plan of Merger (the “Merger Agreement”), by and among the Company, Eclipse Merger Sub I, LLC, Eclipse Merger Sub II, LLC, Endeavor Manager, LLC (solely for purposes of certain sections set forth therein), and Endeavor Parent, LLC (“Endeavor”) to acquire Endeavor (the “Endeavor Acquisition”) for consideration consisting of a base cash amount of $8.0 billion, subject to adjustments under the terms of the Merger Agreement, and approximately 3,800 gross (2,750 net) identified economic potential horizontal drilling locations117.27 million shares of our common stock. The Endeavor Acquisition is expected to close in multiple horizons onthe fourth quarter of 2024, subject to the satisfaction or waiver of customary closing conditions, including the approval of the issuance of our acreagecommon stock in the Endeavor Acquisition by our stockholders and the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. As a result of the Endeavor Acquisition, Endeavor’s equityholders who receive shares of our common stock in the Endeavor Acquisition (the “Endeavor Stockholders”) are expected to hold, at an assumed priceclosing, approximately 39.5% of approximately $60.00 per Bbl WTI. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through additional acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.outstanding common stock.
The challenging commodity price environmentMerger Agreement provides that at the closing of the Endeavor Acquisition, we experienced in 2016 continued in 2017. Commodity prices improved during 2017, but continuedwill enter into an agreement with the Endeavor Stockholders (the “Stockholders Agreement”), which will provide the Endeavor Stockholders with certain director nomination rights, consent rights over certain actions by us and certain shelf, demand and piggyback registration rights. The Endeavor Stockholders will also be subject to certain standstill, voting and transfer restrictions under the Stockholders Agreement.
The foregoing descriptions of the Merger Agreement and the Stockholders Agreement do not purport to be volatile. Nevertheless, we believe we remain well-positionedcomplete and are qualified in their entirety by reference to the actual terms of the Merger Agreement and form of the Stockholders Agreement, copies of which are included hereto as Exhibits 2.3 and 99.3, respectively, and incorporated herein by reference.
See Note 16—Subsequent Events in Item 8. Financial Statements and Supplementary Data and Item 1A. Risk Factors of this environment. During 2017, we again demonstrated our operational focus on achieving best-in-class execution, low-cost operationsreport for additional discussion of the Endeavor Acquisition and a conservative balance sheet as we continued to reduce drilling days, well costs and operating expenses while maintaining what we believe to be a peer leading leverage ratio. We intend to continue our operational focus in 2018, emphasizing full cycle economics and financial discipline. We are operating ten rigs now and currently intend to operate between ten and twelve rigs in 2018, depending on market conditions. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions. We are prepared to decelerate our drilling program if commodity prices deteriorate and continue to accelerate our drilling program should commodity prices remain constant or further improve. We have the option to release up to eight of our current ten rigs in 2018 should commodity prices deteriorate. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”related risks.
Our Business Strategy
Our business strategy is to continue to profitably grow our business throughincludes the following:
Grow production and reserves by developing•Exercise Capital Discipline. During 2023, we continued building on our oil-rich resource base. We intend to drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves andexecution track record, generating free cash flow while generating favorable returns on invested capital.
Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We have targeted various intervalskeeping capital costs under control. Our efficiency gains, particularly in the Midland Basin through horizontal drilling and believe that there are opportunitiescompletion programs, enabled us to target additional intervalsmitigate certain inflationary pressures on variable well costs, which led to a total capital expenditure amount of $2.7 billion, consistent with our guidance presented in November 2023. We expect to continue to exercise capital discipline and plan to spend between $2.30 billion and $2.55 billion in 2024, with the goal of maintaining flat production throughout the stratigraphic column. Our initial horizontal focus had been onyear with less capital and activity than 2023. This capital range accounts for the Wolfcamp B interval, but our recent focus has included the Lower Spraberry, Middle Spraberry and Wolfcamp A intervals. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. As of December 31, 2017, we had drilled 412 horizontal wells as operator and had participated in 61 additional horizontal wells as a non-operator, including two in which we own only a minor wellbore interest. We also acquired interest in 76 horizontal wells on properties we purchased. Of these 549 total horizontal wells, 466 had been completed and were on production. Of the 466 horizontal wells on production, 152 are in the Wolfcamp B interval, 122 are in the Wolfcamp A interval, 163 are in the Lower Spraberry interval, nine are in the Middle Spraberry interval, three are in the Cline interval, three are in the Clearfork interval, seven are in the Bone Spring interval and seven are in various other intervals. These wells have lateral lengths ranging from approximately 2,100 feet to 13,000 feet. In 2018,inflationary pressures we expect to see in 2024.
•Focus on low cost development strategy and continuous improvement in operational, capital allocation and cost efficiencies. Our acreage position is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that our average lateral length will be about 9,300 feet, althoughtakes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the actual length will vary depending on the layoutoperator of approximately 98% of our acreage, which allows us to efficiently manage our operating costs, pace of development activities and other factors. As technology continuesthe gathering and marketing of our production. Our average 81% working interest in our acreage allows us to improve,realize the majority of the benefits of these activities and cost efficiencies.
•Continue to deliver on our enhanced capital return program. We expect to be in a position to continue to deliver on our enhanced capital return program, through which we expect thatintend to distribute 50% of our average lateral length will increase, resulting in higher per well recoveriesquarterly free cash flow to our stockholders. Our capital return program is currently focused on our sustainable and lower development costs per BOE. During the year ended December 31, 2017, we were able to drill our horizontal wells in the Midland Basin with approximately 7,500 foot lateral lengths to total depth, or TD, in an averagegrowing base dividend and a combination of 12.2 daysstock repurchases and we drilled approximately 10,000 foot lateral wells in 14.5 days. Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.
variable dividends.
•Leverage our experience operating in the Permian Basin. Our executive team, which has an average of over 25 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refiningoptimizing and enhancing our drilling and completion techniques. Our focus on efficient drilling and completion techniques is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that the experience of our executive team in deviated and horizontal drilling and completions has helped reduce the execution risk normally associated with these complex well paths. In addition, our completion techniques are continually evolving as we evaluate and implement hydraulic fracturing practices that have and are expected to continue to increase
recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other top operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.
practices compared to our peers.
Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 84% of our acreage. This operational control allows us to manage more efficiently the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average 84% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.
•Pursue strategic acquisitions with substantial resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. OurWe believe our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We regularly review acquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets. During the year ended December 31, 2017, we acquired approximately 99,830 gross (84,468 net) leasehold acres primarily in Pecos and Reeves counties in the Southern Delaware Basin.
•Maintain financial flexibility. We seek to maintain a conservative financial position. In connection with our fall 2017 borrowing base redetermination, the agent lender under our revolving credit agreement recommended a borrowing base of $1.8 billion. We elected a commitment amount of $1.0 billion, of which $603.0 million was available for borrowing as of December 31, 2017. As of December 31, 2017,2023, Diamondback had $556 million of standalone cash and cash equivalents and our borrowing base was set at $1.6 billion, which was fully available for future borrowings. As of December 31, 2023, Viper had $93.5$26 million of cash and cash equivalents, $263 million in outstanding borrowings and $306.5$587 million available for borrowing,future borrowings under its revolving credit facility.
•Deliver on our commitment to environmental, social and governance (“ESG”) performance. We are committed to the safe and responsible development of our resources in the Permian Basin. Our approach to ESG is evidenced through our commitment to people, safety, environmental responsibility, community and sound governance practices. In September 2022, we announced our medium-term goal to reduce Scope 1 and Scope 2 greenhouse gas (“GHG”) intensity by at least 50%, from 2020 levels by 2030.
Our Strengths
We believe that the following strengths will help us achieve our business goals:
•Oil rich resource base in one of North America’s leading resource plays. All Substantially all of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Permian Basin. Our production for the year ended December 31, 2017 was approximately 74% oil, 14% natural gas liquids and 12% natural gas. As of December 31, 2017, our estimated net proved reserves were comprised of approximately 70% oil, 14% natural gas liquids and 16% natural gas.
•Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed economic price of approximately $60.00$50.00 per Bbl WTI, we currently have approximately 3,8007,905 gross (2,750(5,826 net) identified economic potential horizontal drilling locations on our acreage, based on our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately 8,4009,407 feet, with the actual length depending on lease geometry and other considerations. These locations exist across most of our acreage blocks and in multiple horizons. Of these 3,800 locations, 2,100 are in the Midland Basin and 1,700 are in the Delaware Basin. In the Midland Basin, 860 are in the Lower Spraberry or Wolfcamp B horizons where we have drilled a large number of wells, 825 are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wells and 415 are in the Clearfork or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizon is based on 660 foot spacing in f Midland, southwest Martin, northeast Andrews, Howard and Glasscock counties, and 880 foot spacing in all other counties. For the Wolfcamp B horizon, the horizontal location count is based on 660 foot spacing between wells in Midland, Martin, northeast Andrews, Howard, and Glasscock counties, and 880 foot spacing in all other counties. In the Wolfcamp A horizon, the horizontal location count in based on 660 foot spacing in Midland, Howard and Glasscock counties, 880 foot spacing in southwest Martin county and 1,320 foot spacing in other counties. The horizontal location count for the Middle Spraberry is based on 880 foot spacing in Midland, Martin and northeast Andrews counties and 1,320 foot spacing in other counties. In the Cline and Clearfork horizons, the horizontal location count is based on 1,320 foot spacing except for the Clearfork in central Andrews County which is based on 660 foot spacing. In the Delaware Basin, 1,240 locations are in the Wolfcamp A or Wolfcamp B horizons, and 460 locations are in the 2nd Bone Spring or 3rd Bone Spring horizon. The horizontal location counts are based on 880 foot spacing in the Wolfcamp A and Wolfcamp B horizons, and 1,320 foot spacing in the Bone Spring horizons. The ultimate inter-well spacing at these locations may vary from these distances due to different factors, which would result in a higher or lower location count. The two-stream gross estimated ultimate recoveries, or EURs, from our future PUD horizontal wells, as estimated by Ryder Scott as of December 31, 2017, range from 528 MBOE per well, consisting of 413 MBbls of oil and 687 MMcf of natural gas, to 1,665 MBOE per well, consisting of 1,307 MBbls of oil and 2,150 MMcf of natural gas, for wells ranging in lateral length from approximately 5,000 feet to approximately 12,500 feet, in intervals including the Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B. Ryder Scott has estimated gross EURs of 910 MBOE for our Lower Spraberry wells in Midland County and 1,071 MBOE for our Wolfcamp A wells in Pecos County, which constitute 36% of our remaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths. In addition, we have approximately 1,8375,596 square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategic leasehold acquisitions.
•Experienced, incentivized and proven management team. Our executive team has an average of over 25 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, ourOur executive team has significant experience with both drilling and completing horizontal wells in addition to horizontal well reservoir and geologic expertise, which is of strategic importance as we expand our horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.
•Favorable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the longest operating hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that the geological and regulatory environment of the Permian Basin is more stable and predictable, and that we are faced with less operational risks in the Permian Basin, as compared to emerging hydrocarbon basins.
•High degree of operational control. We are the operator of approximately 84%98% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, weWe retain the ability to increase or
decrease our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.
Our Properties
Location and Land
Our total acreage position in the Permian Basin was approximately 246,012 gross (206,660 net) acres at December 31, 2017. We are the operator of approximately 84% of this Permian Basin acreage. In addition, we, through our subsidiary Viper, own mineral interests underlying approximately 247,602 gross acres, 43,843 net acres and 9,570 net royalty acres primarily in the Permian Basin. Approximately 36% of these net royalty acres are operated by us. Since our initial acquisition in the Permian Basin through December 31, 2017, we drilled or participated in the drilling of 753 gross (608 net) wells on our leasehold acreage in this area, primarily targeting the Wolfberry play. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. As of December 31, 2023, our total acreage position in the Permian Basin was approximately 607,877 gross (493,769 net) acres, which consisted primarily of 428,324 gross (349,707 net) acres in the Midland Basin and 174,828 gross (143,742 net) acres in the Delaware Basin. In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 1,197,638 gross acres (34,217 net) royalty acres in the Permian Basin. Approximately 49% of these net royalty acres are operated by us.
We have been developing multiple pay intervals primarily in the Permian Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. We believe our significant experience drilling, completing and operating horizontal wells will allow us to efficiently develop our remaining inventory and ultimately target other horizons that have limited development to date. The following table presents horizontal producing wells in which we have a working interest as of December 31, 2023:
| | | | | | | | |
Basin | | Number of Horizontal Wells |
Midland | | 2,455 | |
Delaware | | 860 | |
Other | | 41 | |
Total(1) | | 3,356 | |
(1) Of these 3,356 total horizontal producing wells, we are the operator of 2,950 wells and have a non-operated working interest in 406 additional wells.
The following table presents the average number of days in which we were able to drill our horizontal wells to total depth specified below during the year ended December 31, 2023:
| | | | | |
| Average Days to Total Depth |
Midland Basin | |
7,500 foot lateral | 7 | |
10,000 foot lateral | 10 | |
13,000 foot lateral | 12 | |
15,000 foot lateral | 12 | |
Delaware Basin | |
7,500 foot lateral | 17 | |
10,000 foot lateral | 17 | |
13,000 foot lateral | 20 | |
15,000 foot lateral | 18 | |
Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.
Equity Method Investments
As of December 31, 2023, we owned interests in the following significant equity method investments:
•a 10% equity interest in EPIC Crude Holdings LP, which owns and operates a long-haul crude oil pipeline from the Permian Basin and the Eagle Ford Shale to Corpus Christi, Texas that is capable of transporting approximately 600,000 Bbl/d.
•a 4% equity interest in Wink to Webster Pipeline LLC, which owns and operates a crude oil pipeline that is capable of transporting approximately 1,000,000 Bbl/d from origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations.
•a 25% equity interest in Remuda Midstream Holdings LLC, which we refer to as the WTG joint venture, which owns and operates an interconnected gas gathering system and seven major gas processing plants servicing the Midland Basin with 1,300 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.
•a 10% equity interest in BANGL LLC, which we refer to as the BANGL joint venture. The BANGL pipeline, which began full commercial service in the fourth quarter of 2021, provides NGL takeaway capacity from the MPLX and WTG gas processing plants in the Permian Basin to the NGL fractionation hub in Sweeny, Texas and has expansion capacity of up to 300,000 Bbl/d.
•a 30% equity interest in Deep Blue, which owns and operates an integrated midstream water infrastructure network with over 800 miles of gathering and redelivery pipelines for gathering, transport, disposal and reuse throughout the Midland Basin. Deep Blue has approximately 2,000,000 Bbl/d of produced water capacity and approximately 66,000,000 Bbl/d of water storage capacity.
Area History
Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Bone Spring, Wolfcamp, Cline, Strawn, Atoka, Barnett and AtokaWoodford formations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It was eventually recognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin. Development in the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependent on oil prices and drilling costs.
The Wolfcamp formation is a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or debris flows with good reservoir properties. Exploration using 2-D seismic data located additional fields, but it was not until the use of 3-D seismic data in the 1990s that the greater extent of the Wolfcamp formation was revealed. The additional potential of the shales within this formation as reservoir rather than just source rocks was not recognized until very recently.
During the late 1990s, Atlantic Richfield Company, or Arco, began a drilling program targeting the base of the Spraberry formation at 10,000 feet, with an additional 200 to 300 feet drilled to produce from the upper portion of the Wolfcamp formation. Henry Petroleum, a private firm, owned interests in the Pegasus field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracturing treatments across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they monetized a portion of their acreage position, which led to the acquisition that enabled us to begin our participation in this play. Recent advancements in enhanced recovery techniques and horizontal drilling continue to make this play attractive to the oil and gas industry. By mid-2010, approximately half of the rigs active in the Permian Basin were drilling wells in the Permian Spraberry, Dean and Wolfcamp formations, which we collectively refer to as the Wolfberry play. Since then, we and most other operators are almost exclusively drilling horizontal wells in the development of unconventional reservoirs in the Permian Basin. As of December 31, 2017,2023, we held working interests in 1,1666,156 gross (937(5,342 net) producing wells and only royalty interests in 6414,696 additional wells.
Geology
The greater Permian Basin formed as an area of rapid Pennsylvanian-Permian subsidence in response to dynamic structural influence.influence of the Marathon Uplift and Ancestral Rockies. It is one of the largestmost productive sedimentary basins in the U.S., with established oil and natural gas production from several stacked reservoirs fromof varying age ranges, most notably Permian through Ordovician in age. The term “Wolfberry” was coined initially to indicate commingled production from
aged sediments. In particular, the Permian aged Wolfcamp, Spraberry Dean and Wolfcamp formations. Time equivalent in the Delaware Basin, the “Wolfbone” play describes vertically commingled production from the Permian Bone Spring Formations have been heavily targeted for several decades. First, through vertical commingling of these zones and, more recently, through horizontal exploitation of each individual horizon. Prior to deposition of the Wolfcamp, formations.Spraberry and Bone Spring Formations, the area of the present-day Permian Basin was a continuous sedimentary feature called the Tabosa Basin. During this time, Ordovician, Silurian, Devonian and Mississippian sediments were laid down in a primarily open marine, shelf setting. However, some time frames saw more restrictive settings that lead to deposits of organically rich mudstone such as the Devonian Woodford and Mississippian Barnett. These formations are important sources and, more recently, reservoirs within the present-day Greater Permian Basin.
The Spraberry/Spraberry and Bone Spring wasFormations were deposited as siliciclastic and carbonate turbidites and debris flows along with pelagic mudstones in a deep water submarine fandeep-water, basinal environment, while the Wolfcamp reservoirs consist of debris-flow, grain-flow and grain-flowfine-grained pelagic sediments, which were also deposited in a submarine fanbasinal setting. The best carbonate reservoirs within the Wolfcamp, Spraberry and Bone Spring are generally found in close proximity to the Central Basin Platform, while the shalemudstone reservoirs within the Wolfcamp thicken basinwardbasin-ward, away from the Central Basin Platform. Both the Spraberry/Bone Spring and Wolfcamp contain organic-rich mudstones and shalesThe mudstone within these reservoirs is organically rich, which when buried to sufficient depth for thermal maturation, became the source of the hydrocarbons found both within the shalesmudstones themselves and in the moreinterbedded conventional clastic and carbonate reservoirs betweenreservoirs. Due to this complexity, the shales. The WolfberryWolfcamp, Spraberry and WolfboneBone Spring intervals are a hybrid reservoir system that contains characteristics of both unconventional “basin-centered oil” resource plays, in the sense that there is no regional downdip oil/water contact.and conventional reservoirs.
We have successfully developed several shalehybrid reservoir intervals within the Clearfork, Spraberry/Bone Spring, Wolfcamp, Barnett and WolfcampWoodford formations since we began horizontal drilling in 2012. The shalesmudstones and some clastics exhibit low permeabilities which necessitate the need for hydraulic fracture stimulation to unlock the vast storage of hydrocarbons in these targets.
We possess, or are in the process of acquiring, 3-D seismic data over substantially all of our major asset areas. Our extensive geophysical database currently includes approximately 1,8375,596 square miles of 3-D data. This data will continue to be utilized in the development of our horizontal drilling program and identification of additional resourceresources to be exploited.
Production Status
During the year ended December 31, 2017, net production from our Permian Basin acreage was 28,917 MBOE, or an average of 79,224 BOE/d, of which approximately 74% was oil, 14% was natural gas liquids and 12% was natural gas.
Facilities
Our oil and natural gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/natural gas/water separation equipment and pumping units.
Recent and Future Activity
During 2018,2024, we expect to drill an estimated 265 to 285 gross (244 to 263 net) operated horizontal wells and complete an estimated 170300 to 190320 gross (146(273 to 163291 net) operated horizontal wells on our acreage. We currently estimate that our capital expenditures in 2018 for drilling and infrastructure2024 will be between $1.3$2.30 billion and $1.5$2.55 billion, consisting of $1.175$2.10 billion to $1.325$2.33 billion for horizontal drilling and completions including non-operated activity and $125.0capital workovers, $200 million to $175.0$220 million for infrastructure and other expenditures, butmidstream investments, excluding joint venture investments and the cost of any leasehold and mineral rightsinterest acquisitions. During the year ended December 31, 2017,2023, we drilled 150350 gross (130(315 net) and completed 123310 gross (105(289 net) operated horizontal wells including five drilled but uncompleted wells we acquired. We participated in the drilling of 16 gross (two net) non-operated horizontal wells in the Permian Basin. During the year ended December 31, 2017, ourand incurred capital expenditures for drilling, completing and equipping wells were $719.3 million.and infrastructure additions to oil and natural gas properties of $2.6 billion. In addition, we spent $124.0$119 million for oil and natural gas infrastructure, $17.4 million for non-operated properties and $2.4 billion for leasehold and mineral rights acquisitions.midstream assets.
We arewere operating ten15 drilling rigs nowand four completion crews at December 31, 2023 and currently intend to operate between ten12 and twelve15 rigs and three and four completion crews on average in 2018, depending on market conditions.2024. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions. We are prepared to decelerate our drilling program if commodity prices deteriorate and continue to accelerate our drilling program should commodity prices remain constant or further improve. We have the option to release up to eight of our current ten rigs in 2018 should commodity prices deteriorate.
Oil and Natural Gas Data
Proved Reserves
Evaluation and Review of Reserves
The estimated reserves as of December 31, 2023 and 2022 are based on reserve estimates prepared by our internal reservoir engineers and audited by Ryder Scott, an independent petroleum engineering firm. Our historical reserve estimates as of December 31, 2017, 2016 and 20152021 were prepared by Ryder Scott with respect to our assetsScott. The internal and those of Viper. Ryder Scott is an independent petroleum engineering firm. Theexternal technical persons responsible for preparing or auditing our proved reserve estimates meet the requirements with regards to 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. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis. The purpose of Ryder Scott’s audits was to provide additional assurance on the reasonableness of internally prepared reserve estimates and covered 100% of our total proved reserves for 2023 and 2022.
Under SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 20172023 were estimated using a deterministic method.
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1)(i) performance-based methods, (2)(ii) volumetric-based methods and (3)(iii) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves forIn general, our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 83% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 17%In certain cases
where there was inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was considered to be inappropriate, the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there werewas inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.
To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scottwe considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.
WeThe process of estimating oil, natural gas and natural gas liquids reserves is complex and requires significant judgment, as discussed in Item 1A. Risk Factors and Item 7. Management Discussion and Analysis—Critical Accounting Estimates of this report. As a result, we maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineersthat have an internal control process to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin.reserves. Our internal technical team membersstaff met with our independent reserve engineersauditor periodically during their audit of the period covered by the reserve reports to discuss the assumptions and methods used in theour proved reserve estimation process. WeAs part of the audit process, we provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Our
The Executive Vice President–Reservoir EngineeringPresident and Chief Engineer is primarily responsible for overseeing the preparation of all of our reserve estimates. Ourestimates and overseeing communications with our independent reserve auditor. The Executive Vice President–Reservoir EngineeringPresident and Chief Engineer is a petroleum engineer with over 3020 years of reservoir and operations experience and our geoscience staff has an average of approximately 2415 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Ryder Scott performed an independent analysis during its audit of our estimated reserves for 2023 and any differences were reviewed with our Executive Vice President and Chief Engineer. For 2023, our reserve auditor’s estimates of our proved reserves did not materially differ from our estimates by more than the established audit tolerance guidelines of ten percent.
The internal control procedures utilized in the preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, and include the following:
•review and verification of historical production data, which data is based on actual production as reported by us;
•preparation of reserve estimates by our Executive Vice President–Reservoir Engineeringthe primary reserve engineers or under histheir direct supervision;
•review by our Executive Vice President–Reservoir Engineeringthe primary reserve engineers of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
•review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;
•direct reporting responsibilities by our Executive Vice President–Reservoir EngineeringPresident and Chief Engineer to our Executive Vice President—Operations;
•prior to finalizing the reserve report, a review of our preliminary proved reserve estimates by our Chief Executive Officer;Officer, President and Chief Financial Officer, Executive Vice President and Chief Operating Officer, Executive Vice President and Chief Engineer and our primary reserves engineers takes place on an annual basis;
•review of our proved reserve estimates by our Audit Committee with our executive team and Ryder Scott on an annual basis;
•verification of property ownership by our land department; and
•no employee’s compensation is tied to the amount of reserves booked.
Potential Drilling Locations
We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price of approximately $50.00 per Bbl WTI, we currently
have approximately 7,905 gross (5,826 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data.
The following table presents our estimated net proved oil and natural gas reserves asthe number of December 31, 2017, 2016 and 2015 (including those attributable to Viper),gross identified economic potential horizontal drilling locations by basin:
| | | | | |
| Number of Identified Economic Potential Horizontal Drilling Locations |
Midland Basin | |
Lower Spraberry(1) | 899 |
Middle Spraberry(1) | 944 |
Wolfcamp A(2) | 565 |
Wolfcamp B(2) | 694 |
Other | 2,150 |
Total Midland Basin | 5,252 |
Delaware Basin | |
2nd Bone Springs(3) | 582 |
3rd Bone Springs(3) | 836 |
Wolfcamp A(3) | 294 |
Wolfcamp B(3) | 530 |
Other | 411 |
Total Delaware Basin | 2,653 |
Total | 7,905 |
(1)Our current location count is based on 660 foot to 880 foot spacing in Midland, Martin and northeast Andrews counties, depending on the reserve reports prepared by Ryder Scott. Each reserve report has been preparedprospect area and 880 foot spacing in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States.all other counties.
|
| | | | | | | | |
| December 31, |
| 2017 | | 2016 | | 2015 |
Estimated proved developed reserves: | | | | | |
Oil (MBbls) | 141,246 |
| | 79,457 |
| | 60,569 |
|
Natural gas (MMcf) | 190,740 |
| | 105,399 |
| | 96,871 |
|
Natural gas liquids (MBbls) | 35,412 |
| | 22,080 |
| | 15,418 |
|
Total (MBOE) | 208,447 |
| | 119,104 |
| | 92,132 |
|
Estimated proved undeveloped reserves: | | | | | |
Oil (MBbls) | 91,935 |
| | 59,717 |
| | 45,409 |
|
Natural gas (MMcf) | 94,629 |
| | 69,497 |
| | 52,632 |
|
Natural gas liquids (MBbls) | 19,198 |
| | 15,054 |
| | 10,586 |
|
Total (MBOE) | 126,905 |
| | 86,354 |
| | 64,767 |
|
Estimated Net Proved Reserves: | | | | | |
Oil (MBbls) | 233,181 |
| | 139,174 |
| | 105,979 |
|
Natural gas (MMcf) | 285,369 |
| | 174,896 |
| | 149,503 |
|
Natural gas liquids (MBbls) | 54,610 |
| | 37,134 |
| | 26,004 |
|
Total (MBOE)(1) | 335,352 |
| | 205,458 |
| | 156,899 |
|
Percent proved developed | 62.2 | % | | 58.0 | % | | 58.7 | % |
| |
(1) | Estimates of reserves as of December 31, 2017, 2016 and 2015 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2017, 2016 and 2015, respectively, in accordance with SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
The foregoing reserves are all located within the continental United States. Reserve engineering(2)Our current location count is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables660 foot to 880 foot spacing in Midland and assumptions,Howard counties, depending on the prospect area and 880 foot spacing in all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A.“Risk Factors.” We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.counties.
(3)Our current location count is based on 880 foot to 1,320 foot spacing.
Proved Undeveloped Reserves (PUDs)
As of December 31, 2017, our proved undeveloped reserves totaled 91,935 MBbls of oil, 94,629 MMcf of natural gas and 19,198 MBbls of natural gas liquids, for a total of 126,905 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
The following table includes the changes in PUD reserves for 2017:
|
| | |
| (MBOE) |
Beginning proved undeveloped reserves at December 31, 2016 | 86,354 |
|
Undeveloped reserves transferred to developed | (31,666 | ) |
Revisions | (4,710 | ) |
Net purchases | 6,246 |
|
Extensions and discoveries | 70,680 |
|
Ending proved undeveloped reserves at December 31, 2017 | 126,904 |
|
The increase in proved undeveloped reserves was primarily attributable to extensions of 67,676 MBOE from 87 gross (75 net) wells in which we have a working interest and 3,004 MBOE from 40 gross wells in which Viper owns royalty interests. Of the 87 gross wells, 26 were in the Delaware Basin. Transfers of 31,666 MBOE were the result of drilling or participating in 44 gross (37 net) horizontal wells in which we have a working interest and 27 gross wells in which we have a royalty interest or mineral interest through Viper. We own a working interest in 23 of the 27 gross Viper wells. Net purchases of 6,246 MBOE were primarily from our purchase in Pecos and Reeves counties. Downward revisions of 4,710 MBOE resulted from reclassification of seven locations and technical revisions.
Costs incurred relating to the development of PUDs were approximately $145.4 million during 2017. Estimated future development costs relating to the development of PUDs are projected to be approximately $595.4 million in 2018, $205.6 million in 2019, $171.2 million in 2020 and $58.3 million in 2021. Since our current executive team assumed management control in 2011, our average drilling costs and drilling times have been reduced. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.
As of December 31, 2017, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.
As of December 31, 2017, none of our total proved reserves were classified as proved developed non-producing.
Oil and Natural Gas Production Prices and Production Costs
Production and Price History
The following table setstables set forth information regarding our net production of oil, natural gas and natural gas liquids allby basin for the fields containing 15% or more along with other production from fields containing less than 15% of our total proved reserves:
| | | | | | | | | | | | | | | | | | | | | | | |
| Midland Basin | | Delaware Basin | | Other(1)(2) | | Total |
Production Data: | | | | | | | |
Year Ended December 31, 2023 | | | | | | | |
Oil (MBbls) | 75,859 | | | 20,246 | | | 71 | | | 96,176 | |
Natural gas (MMcf) | 140,721 | | | 57,129 | | | 267 | | | 198,117 | |
Natural gas liquids (MBbls) | 25,899 | | | 8,296 | | | 22 | | | 34,217 | |
Total (MBOE) | 125,212 | | | 38,064 | | | 138 | | | 163,413 | |
| | | | | | | |
Year Ended December 31, 2022 | | | | | | | |
Oil (MBbls) | 58,803 | | | 22,681 | | | 132 | | | 81,616 | |
Natural gas (MMcf) | 116,579 | | | 59,338 | | | 459 | | | 176,376 | |
Natural gas liquids (MBbls) | 20,800 | | | 9,016 | | | 64 | | | 29,880 | |
Total (MBOE) | 99,033 | | | 41,587 | | | 273 | | | 140,892 | |
| | | | | | | |
Year Ended December 31, 2021 | | | | | | | |
Oil (MBbls) | 52,112 | | | 25,672 | | | 3,738 | | | 81,522 | |
Natural gas (MMcf) | 96,083 | | | 66,034 | | | 7,289 | | | 169,406 | |
Natural gas liquids (MBbls) | 17,010 | | | 8,749 | | | 1,487 | | | 27,246 | |
Total (MBOE) | 85,136 | | | 45,427 | | | 6,440 | | | 137,002 | |
(1)Production data includes Rockies and High Plains for the years ended December 31, 2023, 2022 and 2021, and Eagle Ford Shale through October 1, 2022, the effective date on which is fromit was divested.
(2)Production data includes Eagle Ford Shale, Appalachia, Barnett, Denver-Julesburg, Mid-Con, and Williston beginning November 1, 2023, the Permian Basin in West Texas, andeffective date on which the properties were acquired.
The following table sets forth certain price and cost information for each of the periods indicated:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
Average Prices: | | | | | |
Oil ($ per Bbl) | $ | 75.68 | | | $ | 93.85 | | | $ | 66.19 | |
Natural gas ($ per Mcf) | $ | 1.32 | | | $ | 4.86 | | | $ | 3.36 | |
Natural gas liquids ($ per Bbl) | $ | 20.08 | | | $ | 35.07 | | | $ | 28.70 | |
Combined ($ per BOE) | $ | 50.35 | | | $ | 67.90 | | | $ | 49.25 | |
| | | | | |
Oil, hedged ($ per Bbl)(1) | $ | 74.72 | | | $ | 86.76 | | | $ | 52.56 | |
Natural gas, hedged ($ per Mcf)(1) | $ | 1.48 | | | $ | 4.12 | | | $ | 2.39 | |
Natural gas liquids, hedged ($ per Bbl)(1) | $ | 20.08 | | | $ | 35.07 | | | $ | 28.33 | |
Average price, hedged ($ per BOE)(1) | $ | 49.98 | | | $ | 62.85 | | | $ | 39.87 | |
| | | | | |
Average Costs per BOE: | | | | | |
Lease operating expenses | $ | 5.34 | | | $ | 4.63 | | | $ | 4.12 | |
Production and ad valorem taxes | 3.21 | | | 4.34 | | | 3.10 | |
Gathering, processing and transportation expense | 1.76 | | | 1.83 | | | 1.55 | |
General and administrative - cash component | 0.59 | | | 0.63 | | | 0.69 | |
Total operating expense - cash | $ | 10.90 | | | $ | 11.43 | | | $ | 9.46 | |
| | | | | |
General and administrative - non-cash component | $ | 0.33 | | | $ | 0.39 | | | $ | 0.37 | |
Depreciation, depletion, amortization and accretion per BOE | 10.68 | | | 9.54 | | | 9.31 | |
Interest expense, net | 1.07 | | | 1.13 | | | 1.45 | |
Merger and integration expense | 0.07 | | | 0.10 | | | 0.57 | |
Total operating expense - non-cash | $ | 12.15 | | | $ | 11.16 | | | $ | 11.70 | |
| | | | | |
Production Costs(2) | $ | 7.10 | | | $ | 6.46 | | | $ | 5.67 | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Production Data: | | | | | |
Oil (MBbls) | 21,418 |
| | 11,562 |
| | 9,081 |
|
Natural gas (MMcf) | 20,660 |
| | 10,728 |
| | 7,931 |
|
Natural gas liquids (MBbls) | 4,056 |
| | 2,399 |
| | 1,678 |
|
Combined volumes (MBOE) | 28,917 |
| | 15,749 |
| | 12,081 |
|
Daily combined volumes (BOE/d) | 79,224 |
| | 43,031 |
| | 33,098 |
|
| | | | | |
Average Prices: | | | | | |
Oil (per Bbl) | $ | 48.75 |
| | $ | 40.70 |
| | $ | 44.68 |
|
Natural gas (per Mcf) | 2.53 |
| | 2.10 |
| | 2.47 |
|
Natural gas liquids (per Bbl) | 22.20 |
| | 14.20 |
| | 12.77 |
|
Combined (per BOE) | 41.02 |
| | 33.47 |
| | 36.98 |
|
Oil, hedged ($ per Bbl)(1) | 48.94 |
| | 40.80 |
| | 60.63 |
|
Natural gas, hedged ($ per MMbtu)(1) | 2.65 |
| | 2.06 |
| | 2.47 |
|
Average price, hedged ($ per BOE)(1) | 41.26 |
| | 33.54 |
| | 48.97 |
|
| | | | | |
Average Costs per BOE: | | | | | |
Lease operating expense | $ | 4.38 |
| | $ | 5.23 |
| | $ | 6.84 |
|
Production and ad valorem taxes | 2.54 |
| | 2.19 |
| | 2.73 |
|
Gathering and transportation expense | 0.44 |
| | 0.74 |
| | 0.50 |
|
General and administrative - cash component | 0.80 |
| | 1.03 |
| | 1.11 |
|
Total operating expense - cash | 8.16 |
| | 9.19 |
| | 11.18 |
|
| | | | | |
General and administrative - non-cash component | 0.88 |
| | 1.68 |
| | 1.54 |
|
Depreciation, depletion and amortization | 11.30 |
| | 11.30 |
| | 18.02 |
|
Interest expense | 1.40 |
| | 2.58 |
| | 3.44 |
|
Total expenses | $ | 13.58 |
| | $ | 15.56 |
| | $ | 23.00 |
|
| |
(1) | Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. |
(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
Productive Wells(2)Average production costs exclude production and ad valorem taxes.
Wells Drilled and Completed in 2023
The following table sets forth the total number of operated horizontal wells drilled and completed during the year ended December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 |
| Drilled | | Completed |
Area: | Gross | | Net | | Gross | | Net |
Midland Basin | 315 | | | 285 | | | 263 | | | 246 | |
Delaware Basin | 35 | | | 30 | | | 47 | | | 43 | |
| | | | | | | |
Total | 350 | | | 315 | | | 310 | | | 289 | |
As of December 31, 2017,2023, we operated the following wells:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Vertical Wells | | Horizontal Wells | | Total |
Area: | Gross | | Net | | Gross | | Net | | Gross | | Net |
Midland Basin | 2,641 | | | 2,499 | | | 2,269 | | | 2,088 | | | 4,910 | | | 4,587 | |
Delaware Basin | 37 | | | 35 | | | 681 | | | 633 | | | 718 | | | 668 | |
| | | | | | | | | | | |
Total | 2,678 | | | 2,534 | | | 2,950 | | | 2,721 | | | 5,628 | | | 5,255 | |
Productive Wells
As of December 31, 2023, we owned an interest in a total of 20,852 gross productive wells with an average unweighted 80%87% working interest in 1,1666,156 gross (937(5,342 net) productive wells and an average 2.7%2.4% royalty interest in 6414,696 additional wells. Through our subsidiary Viper, we own an average unweighted 9.2% royalty or mineral2.5% net revenue interest in 1,28714,893 of the total 20,852 gross productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
Acreage
The following table sets forth information regarding productive wells by basin as of December 31, 2017 relating to our leasehold acreage:2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross Wells | | Net Wells |
| Oil | | Natural Gas | | Total | | Oil | | Natural Gas | | Total |
Midland Basin | 14,137 | | | 36 | | | 14,173 | | | 4,633 | | | 9 | | | 4,642 | |
Delaware Basin | 3,406 | | | 494 | | | 3,900 | | | 677 | | | 22 | | | 699 | |
Denver-Julesburg Basin | 1,435 | | | 118 | | | 1,553 | | | — | | | — | | | — | |
Williston Basin | 721 | | | 2 | | | 723 | | | — | | | — | | | — | |
Other(1) | 291 | | | 212 | | | 503 | | | 1 | | | — | | | 1 | |
Total productive wells | 19,990 | | | 862 | | | 20,852 | | | 5,311 | | | 31 | | | 5,342 | |
|
| | | | | | | | | | | | | | | | | |
| Developed Acreage(1) | | Undeveloped Acreage(2) | | Total Acreage(3) |
Basin | Gross(4) | | Net(5) | | Gross(4) | | Net(5) | | Gross(4) | | Net(5) |
Delaware | 58,444 |
| | 49,919 |
| | 69,982 |
| | 54,800 |
| | 128,426 |
| | 104,719 |
|
Midland | 84,325 |
| | 69,641 |
| | 33,261 |
| | 32,300 |
| | 117,586 |
| | 101,941 |
|
Total | 142,769 |
| | 119,560 |
| | 103,243 |
| | 87,100 |
| | 246,012 |
| | 206,660 |
|
| |
(1) | Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells. |
| |
(2) | Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. |
| |
(3) | Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests. |
| |
(4) | A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. |
| |
(5) | A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. |
(1)Other productive wells include the Eagle Ford Basin, Appalachia Basin, Mid-Con, Rockies Basin and Barnett Basin.
Undeveloped acreage expirations
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2017, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019 | | 2020 | | 2021 | | 2022 |
Basin | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Delaware | 28,572 |
| | 22,198 |
| | 31,091 |
| | 19,415 |
| | 13,097 |
| | 1,286 |
| | 3,639 |
| | 719 |
| | — |
| | — |
|
Midland | 897 |
| | 715 |
| | 908 |
| | 255 |
| | 19,678 |
| | 18,933 |
| | — |
| | — |
| | — |
| | — |
|
Total | 29,469 |
| | 22,913 |
| | 31,999 |
| | 19,670 |
| | 32,775 |
| | 20,219 |
| | 3,639 |
| | 719 |
| | — |
| | — |
|
Drilling Results
The following table setstables set forth information with respect to the number of wells completeddrilled during the periods indicated.indicated by basin. Each of these wells was drilled in the Permian Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 |
| Midland Basin | | Delaware Basin | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
Development: | | | | | | | | | | | |
Productive | 192 | | | 179 | | | 29 | | | 25 | | | 221 | | | 204 | |
Dry | — | | | — | | | — | | | — | | | — | | | — | |
Exploratory: | | | | | | | | | | | |
Productive | 123 | | | 106 | | | 6 | | | 5 | | | 129 | | | 111 | |
Dry | — | | | — | | | — | | | — | | | — | | | — | |
Total: | | | | | | | | | | | |
Productive | 315 | | | 285 | | | 35 | | | 30 | | | 350 | | | 315 | |
Dry | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| Midland Basin | | Delaware Basin | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
Development: | | | | | | | | | | | |
Productive | 59 | | | 54 | | | 16 | | | 15 | | | 75 | | | 69 | |
Dry | — | | | — | | | — | | | — | | | — | | | — | |
Exploratory: | | | | | | | | | | | |
Productive | 138 | | | 129 | | | 27 | | | 25 | | | 165 | | | 154 | |
Dry | — | | | — | | | — | | | — | | | — | | | — | |
Total: | | | | | | | | | | | |
Productive | 197 | | | 183 | | | 43 | | | 40 | | | 240 | | | 223 | |
Dry | — | | | — | | | — | | | — | | | — | | | — | |
|
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
Development: | | | | | | | | | | | |
Productive | 27 |
| | 23 |
| | 6 |
| | 3 |
| | 8 |
| | 6 |
|
Dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Exploratory: | | | | | | | | | | | |
Productive | 112 |
| | 84 |
| | 82 |
| | 62 |
| | 71 |
| | 57 |
|
Dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total: | | | | | | | | | | | |
Productive | 139 |
| | 107 |
| | 88 |
| | 65 |
| | 79 |
| | 63 |
|
Dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2021 |
| Midland Basin | | Delaware Basin | | | | Total |
| Gross | | Net | | Gross | | Net | | | | | | Gross | | Net |
Development: | | | | | | | | | | | | | | | |
Productive | 33 | | | 30 | | | 7 | | | 7 | | | | | | | 40 | | | 37 | |
Dry | — | | | — | | | — | | | — | | | | | | | — | | | — | |
Exploratory: | | | | | | | | | | | | | | | |
Productive | 142 | | | 135 | | | 34 | | | 31 | | | | | | | 176 | | | 166 | |
Dry | — | | | — | | | — | | | — | | | | | | | — | | | — | |
Total: | | | | | | | | | | | | | | | |
Productive | 175 | | | 165 | | | 41 | | | 38 | | | | | | | 216 | | | 203 | |
Dry | — | | | — | | | — | | | — | | | | | | | — | | | — | |
As of December 31, 2017,2023, we had 8317 gross (66(16 net) operated wells in the process of drilling and 205 gross (181 net) wells in the process of drilling, completingcompletion or dewatering or shut in awaiting infrastructurewaiting on completion.
Acreage
The following table sets forth information as of December 31, 2023 relating to our leasehold acreage:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Developed Acreage(1) | | Undeveloped Acreage | | Total Acreage(2) |
Basin | Gross | | Net | | Gross | | Net | | Gross | | Net |
Midland | 218,357 | | | 191,532 | | | 209,967 | | | 158,175 | | | 428,324 | | | 349,707 | |
Delaware | 102,312 | | | 79,895 | | | 72,516 | | | 63,847 | | | 174,828 | | | 143,742 | |
| | | | | | | | | | | |
Conventional Permian | — | | | — | | | 4,725 | | | 320 | | | 4,725 | | | 320 | |
| | | | | | | | | | | |
Total | 320,669 | | | 271,427 | | | 287,208 | | | 222,342 | | | 607,877 | | | 493,769 | |
(1)Does not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.
(2)Does not reflected ininclude Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.
Undeveloped Acreage Expirations
As of December 31, 2023, the above table.following gross and net undeveloped acres are set to expire over the next five years based on their contractual lease maturities unless (i) production is established within the spacing units covering the acreage or (ii) the lease is renewed or extended under continuous drilling provisions prior to the contractual expiration dates.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Acres Expiring | | | | |
| Midland | | Delaware | | | | | | Total | | |
| Gross | | Net | | Gross | | Net | | | | | | | | | | Gross | | Net | | | | |
2024 | 10,839 | | | 8,805 | | | 3 | | | 2 | | | | | | | | | | | 10,842 | | | 8,807 | | | | | |
2025 | 4,143 | | | 3,366 | | | — | | | — | | | | | | | | | | | 4,143 | | | 3,366 | | | | | |
2026 | 2,862 | | | 2,325 | | | 428 | | | 347 | | | | | | | | | | | 3,290 | | | 2,672 | | | | | |
2027 | 5 | | | 4 | | | — | | | — | | | | | | | | | | | 5 | | | 4 | | | | | |
2028 | 59 | | | 48 | | | — | | | — | | | | | | | | | | | 59 | | | 48 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
Total | 17,908 | | | 14,548 | | | 431 | | | 349 | | | | | | | | | | | 18,339 | | | 14,897 | | | | | |
Title to Properties
As is customary inPrior to the drilling of an oil andor natural gas well, it is the normal practice in our industry we initially conduct only a cursory reviewfor the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations.the well. To the extent title opinions or other investigations reflect title defects on those properties,impacting the development or operation of a producing property, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.defects. We have obtained title opinions on substantially all of
our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review, or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
Marketing and Customers
We typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2017,2023, four purchasers each accounted for more than 10% of our revenue. For the year ended December 31, 2022, two purchasers each accounted for more than 10% of our revenue. For the year ended December 31, 2021, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%);revenue. We do not require collateral and Enterprise Crude Oil LLC (11%). Fordo not believe the year ended December 31, 2016, three purchasers each accounted for more than 10%loss of any single purchaser would materially impact our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasingoperating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. For additional information regarding our customer concentrations, see Note 3—Revenue from us, revenue could declineContracts with Customers in Item 8. Financial Statements and Supplementary Data of this report.
Delivery Commitments
Certain of our operating resultsfirm sales agreements include delivery commitments that specify the delivery of a fixed and financial condition coulddeterminable quantity of oil. We expect our production and reserves will continue to be harmed.
We have entered into an oil purchase agreement with Shell Trading (US) Companythe primary means of fulfilling our future commitments. However, these contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate to satisfy our commitment. Beginning in
which2023, we
agreedbegan purchasing third-party volumes to
sell specified quantities of oilfulfill a certain delivery commitment to
Shell Trading (US) Company. Our agreement with Shell Trading (US) Company has an initial term of five years ending September 30, 2018. The agreement may also be terminated by Shell Trading (US) Company by written notice to usa pipeline in the
event that Shell Trading (US) Company’s contract for transportation on the pipeline is terminated. Our maximum delivery obligation underPermian Basin. For additional information regarding commitments, see Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this agreement is 8,000 gross barrels per day. We have a one-time right to elect to decrease the contract quantity by not more than 20% of the then-current quantity. This decreased contract quantity, if elected, would be effective forreport.
the remainder of the term of the agreement. Shell Trading (US) Company has agreed to pay to us the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If we fail to deliver the required quantities of oil under the agreement during any three-month period following the service commencement date, we have agreed to pay Shell Trading (US) Company a deficiency payment, which is calculated by multiplying (i) the volume of oil that we failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency volume is calculated.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that may have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Transportation
During the initial development of our fields we evaluate all gathering and delivery infrastructure in the areas of our production. Currently, a majority of our production in the Midland Basin is transported to purchasers by pipeline. We anticipate that our production in the Delaware Basin transported to purchasers by pipeline will increase to 80% by the end of 2018. During 2018, several oil and saltwater disposal gathering systems were installed. We believe that these gathering systems will help us reduce our lease operating expense and improve our margins on sales in future periods.
The following table presents the average percentage of produced oil sold by pipeline and the average percentage of produced water connected to saltwater disposals by pipeline:
|
| | | | | | | | |
| Midland Basin | | Delaware Basin | | Total |
% of produced oil sold by pipeline | 93 | % | | 22 | % | | 80 | % |
% of produced water connected to pipeline | 93 | % | | 87 | % | | 91 | % |
The following table presents the average cost per Bbl to transport produced oil and water by truck and by pipeline as well as the average savings of transporting produced oil and water by pipeline versus truck:
|
| | | | | | | |
| Midland Basin | | Delaware Basin |
Oil transportation costs per Bbl: | | | |
Trucked | $ | 1.84 |
| | $ | 2.28 |
|
Pipeline | $ | 1.09 |
| | $ | 1.31 |
|
Average savings | $ | 0.75 |
| | $ | 0.97 |
|
| | | |
Water transportation costs per Bbl: | | | |
Trucked | $ | 2.08 |
| | $ | 1.86 |
|
Pipeline | $ | 0.23 |
| | $ | 0.39 |
|
Average savings | $ | 1.85 |
| | $ | 1.47 |
|
Oil and Natural Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.50%15% to 25.00%35%, resulting in a net revenue interest to us generally ranging from 75.00%65% to 87.50%85%.
Seasonal Nature of Business
Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Certain natural gas usersbuyers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. SeasonalIn our exploration and production business, seasonal weather conditions, and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.
Regulation
Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislationrequirements. Legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.
Environmental Matters and Regulation
Matters. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.
Waste Handling. The Resource Conservation and Recovery Act, or the RCRA, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the Resource Conservation and Recovery Act,RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the Resource Conservation and Recovery Act,RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in the U.S. Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and natural gas waste. It has until MarchHowever, in April 2019, the EPA concluded that revisions to determine whether any revisionsthe federal regulations for the management of oil and natural gas waste are necessary.not necessary at this time. Any such changes in thesuch laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” or the CWA, the Safe Drinking Water Act, the Oil Pollution Act, or the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water ActCWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.
The scope of waters regulated under the CWA has fluctuated in recent years. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or the USACE,Corps, jointly promulgated final rules redefiningexpanding the scope of waters protected under the Clean Water Act. ToCWA. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules, and then, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rule, and significantly reducing the waters subject to federal regulation under the CWA. On August 30, 2021, a federal court struck down the replacement rule and, on January 18, 2023, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015. However, on May 25, 2023, the Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected by the CWA. On September 8, 2023, the EPA and the Corps published a final rule conforming their regulations to the decision. These recent actions have provided some clarity. However, to the extent the rule expandsEPA and the Corps broadly interpret their jurisdiction and expand the range of properties subject to the Clean Water Act’sCWA’s jurisdiction, we or third-party operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Following its promulgation, numerous states and industry groups challenged the rule and, on October 9, 2015, a federal court stayed the rule’s implementation nationwide, pending further action in court. In response to this decision, the EPA and the USACE have resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Further, on February 28, 2017, President Trump signed an executive order directing the relevant executive agencies to review the rules and to initiate rulemaking to rescind or revise them, as appropriate under the stated policies of protecting navigable waters from pollution while promoting economic growth, reducing uncertainty, and showing due regard for Congress and the states. On July 27, 2017, the EPA and the USACE published a proposed rule to rescind the 2015 rules, and, on November 22, 2017, the agencies published a proposed rule to maintain the status quo pending the agencies review of the 2015 rules.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “–“—Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
The Oil Pollution ActOPA is the primary federal law for oil spill liability. The Oil Pollution ActOPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution ActOPA subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.
Non-compliance with the Clean Water ActCWA or the Oil Pollution ActOPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.
Air Emissions. The federal Clean Air Act, or the CAA, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air ActCAA that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “–“—Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Additionally, on April 17, 2023, the EPA agreed in a consent decree to issue a proposed rule by December 10, 2024 that
either revises its emission standards for hazardous air pollutants from oil and natural gas production activities or determines that no revision is necessary. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air ActCAA and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.
Climate Change. In December 2009,recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. For example, the Infrastructure Investment and Jobs Act of 2021 and the Inflation Reduction Act of 2022, or the IRA, include billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration. Also, the EPA issued an Endangerment Finding that determined thathas proposed ambitious rules to reduce harmful air pollutant emissions, of carbon dioxide, methane and otherincluding greenhouse gases, presentfrom light-, medium-, and heavy-duty vehicles beginning in model year 2027. These incentives and regulations could accelerate the transition of the economy away from the use of fossil fuels toward lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell and adversely impact our business. In addition, the IRA imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA amends the CAA to impose a fee on the emission of methane that exceeds an endangermentapplicable waste emissions threshold from sources required to public health and the environment because, accordingreport their greenhouse gas emissions to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new greenhouse gas emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their greenhouse gas emissions. The Court ruled, however, that the EPA may require installation of best available control technology for greenhouse gas emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on greenhouse gas permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.
Additionally, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emissionincluding those sources in the U.S., including natural gas liquids fractionatorsoffshore and local natural gas distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded the greenhouse gas reporting rule to include onshore and offshore oilpetroleum and natural gas production and onshore processing, transmission, storagegathering and distribution facilities, which may includeboosting source categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025 and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain of our facilities, beginningthresholds established in 2012 for emissions occurring in 2011. In October 2015,the IRA. On January 12, 2024, the EPA amended the greenhouse gas reportingannounced a proposed rule to addimplement the reportingmethane emissions charge. The methane emissions charge could increase our operating costs, which could adversely impact our business, financial condition and cash flows.
The EPA has also finalized a series of greenhouse gas monitoring, reporting and emissions from gatheringcontrol rules for the oil and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.
In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gasesindustry, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas capcap-and-trade programs. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and trade programs. Althoughnatural gas operations. For example, on November 4, 2020, the U.S. Congress has notTexas Railroad Commission adopted such legislation at this time, it may do so innew guidance on when flaring is permissible, requiring operators to submit more specific information to justify the future and many states continueneed to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants,flare or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.vent gas.
At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework forOn April 21, 2021, the parties to cooperateUnited States announced that it was setting an economy-wide target of reducing its greenhouse gas emissions by 50-52 percent below 2005 levels in 2030. In November 2021, in connection with the 26th Conference of the Parties in Glasgow, Scotland, the United States and report actionsother world leaders made further commitments to reduce greenhouse gas emissions. However,emissions, including reducing global methane emissions by at least 30% by 2030 from 2020 levels. More than 150 countries have now signed on June 1, 2017, President Trump announced thatto this pledge. Most recently, at the 28th Conference of the Parties in the United States would withdrawArab Emirates, world leaders agreed to transition away from the Paris Agreement,fossil fuels in a just, orderly and begin negotiationsequitable manner and to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect
one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement.triple renewables and double energy efficiency globally by 2030. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth insupport the international accord.climate commitments.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.
Regulation of Hydraulic Fracturing
Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of the U.S. Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing
with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.
In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, onOn June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
On August 16, 2012, the EPA published final regulations under the federal Clean Air ActCAA that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will
likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, on August 13, 2020, in a March 28, 2017response to an executive order by former President Trump directedto review and revise unduly burdensome regulations, the EPA amended the 2012 and 2016 New Source Performance standards to review the 2016 regulationsease regulatory burdens, including rescinding standards applicable to transmission or storage segments and if appropriate, to initiateeliminating methane requirements altogether. On June 30, 2021, President Biden signed into law a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe developmentjoint resolution of the nation’s energy resources, while atU.S. Congress disapproving the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017,2020 amendments (with the exception of some technical changes) thereby reinstating the 2012 and 2016 New Source Performance standards. The EPA expects owners and operators of regulated sources to take “immediate steps” to comply with these standards. Additionally, on December 2, 2023, the EPA publishedannounced a proposedfinal rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations. These new standards, to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. These standards,extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy the U.S. Geological Survey, and the U.S. Government Accountability Office,Department of the Interior have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments
designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits and temporarily suspend operations for waste disposal wells. For example, in September 2021, the Texas Railroad Commission curtailed the amount of water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has subsequently suspended some permits there and expanded the restrictions to other areas. In addition, the Texas Railroad Commission has imposed monitoring and reporting requirements for any new disposal well permitted in the Permian Basin. These restrictions on use of produced water, a moratorium on new produced water disposal wells, and additional monitoring and reporting requirements could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or pump it through the pipeline network or other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling and completion activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Endangered Species. The federal Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species, such as the recently listed lesser prairie chicken, are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. However, the designation of previously unprotected species, such as the dunes sagebrush lizard (proposed as endangered on July 3, 2023), in areas where we operate as threatened or endangered could result in the imposition of restrictions on our operations and consequently have a material adverse effect on our business.
Other Regulation of the Oil and Natural Gas Industry
Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the
regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas prices are currently unregulated, the U.S. Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.
Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:
following; the location of wells;
the method of drilling and casing wells;
the timing of construction or drilling activities, including seasonal wildlife closures;
the rates of production or “allowables”;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.
Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Natural Gas Sales and Transportation.Sales. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates or negotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.
Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, the U.S. Congress could reenact price controls in the future.
Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act, and intrastatewe have a tariff on file with FERC to perform oil gathering service in interstate commerce. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines, including us, must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Safety and Maintenance Regulation. In our midstream operations, we are subject to regulation by the U.S. Department of Transportation, or DOT, underthe Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including natural gas liquids and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.
We are also subject to the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Act establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the Pipeline and Hazardous Materials Safety Administration, or PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.
The Pipeline Safety and Job Creation Act, enacted in 2011, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, also known as the PIPES Act, enacted in 2016, amended the HLPSA and increased safety regulation. The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $266,015 and $2,660,135, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. The PIPES Act ensures that the PHMSA completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.
PHMSA has undertaken rulemakings to address many areas of this legislation. For example, on October 1, 2019, PHMSA published final rules to expand its integrity management requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside High Consequence Areas. Also, on November 15, 2021, PHMSA published a final rule extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements for certain gas gathering pipelines with large diameters and high operating pressures, and, on August 24, 2022, PHMSA published a final rule strengthening integrity management requirements for onshore gas transmission lines, bolstering corrosion control standards and repair criteria, and imposing new requirements for inspections after extreme weather events. Further, on May 18, 2023, PHMSA published a proposed rule to reduce methane emissions from new and existing gas pipelines, underground natural gas storage facilities, and liquefied natural gas facilities. These requirements and related rule making proceedings, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flow.
States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have undertaken responsibility to enforce the federal standards. For example, on December 17, 2019, the Texas Railroad Commission adopted rules requiring that operators of gathering lines take 'appropriate' actions to fix safety hazards. We do not anticipate any significant problems in complying with applicable federal and state laws and regulations in Texas. Our gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Rattler LLC and the entities in which it owns an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified
thresholds, or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. Also, the Department of Homeland Security and other agencies such as the EPA continue to develop regulations concerning the security of industrial facilities, including crude oil and natural gas facilities. We are subject to a number of requirements and must prepare Federal Response Plans to comply. We must also prepare Risk Management Plans under the regulations promulgated by the EPA to implement the requirements under the CAA to prevent the accidental release of extremely hazardous substances. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements. We believe that we are in compliance in all material respects with all applicable laws and regulations relating to safety and security.
State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Operational Hazards and Insurance
The oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.
In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, rig physical damage protection, control of well protection for selectedall wells,
comprehensive general liability, commercial automobile, workers compensation, pollution liability (claims made coverage with a policy retroactive date)date and occurrence-based coverage for sudden, accidental releases), excess umbrella liability and other coverage.
Our insurance is subject to exclusioncertain exclusions and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. See ItemItem 1A. “Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Operating hazardsRisk Factors of this report for additional information regarding operating hazard and uninsured risks may result in substantial losses and could prevent us from realizing profits.”risks.
We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.
Generally, we also require our third partythird-party vendors to sign master service agreements in which they agree to indemnify us for property damage and injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.
Human Capital
We have developed a culture grounded upon the solid foundation of our core values—leadership, integrity, excellence, people and teamwork—that are adhered to throughout our company. We set a high bar for all of our employees in terms of how they operate and interact, both within the office and out in the field. We challenge them to identify new ways to foster a better future for themselves and for us. Our board of directors, through its Safety, Sustainability and Corporate Responsibility Committee, which we refer to as the SS&CR Committee, provides an important oversight of our human capital management strategy, including diversity, equity and inclusion. The SS&CR Committee receives regular updates from our executive leadership, senior management and third-party consultants on human capital trends and other key human capital matters impacting our business.
As of December 31, 2017,2023, we had approximately 2511,023 full time employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hireutilize independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full timefull-time employees.
Diversity, Inclusion, Recruiting and Retention
Equal employment opportunity is one of our core tenets and, as such, our employment decisions are based on merit, qualifications, competencies and contributions. We actively seek to attract and retain an increasingly diverse workforce and continue to cultivate our respectful work environment. We value the perspectives, experiences and ideas contributed by our employees from a diverse range of ethnic, cultural and ideological backgrounds. Over 28% of our employees are women and over 35% of our employees self-identify as ethnic minorities as of December 31, 2023. We disclosed our 2022 Equal Employment Opportunity (EEO-1) data as of December 31, 2022 in our 2023 Corporate Sustainability Report in an effort to provide additional transparency into the Company’s workforce demographics.
In 2023, we took various actions to increase the diversity of job applicants and expand our recruitment efforts, particularly in our college recruitment and internship programs. We collaborated with several student organizations to reinforce this inclusive initiative, which will continue in the future. In addition, we have focused on recruiting experienced hires to target and retain top industry talent. We have historically had a low annual attrition rate, representing approximately 14% in 2023, despite the challenging labor market and increased competition for talent impacted by the potential economic downturn and the high inflationary environment. We believe that our low attrition rate is in part a result of our corporate culture focused on diversity and inclusion, teamwork and commitment to employee development and career advancement discussed in more detail below.
Health and Safety
Protecting employees, the public and the environment is a top priority in our operations and in the way we manage our assets. We are focused on minimizing the risk of workplace incidents and preparing for emergencies as an ingrained element of our corporate responsibility. We also strive to comply with all applicable health, safety and environmental standards, laws and regulations.
We have committed to reduce injuries and fatalities in our business and are focused on safety culture improvements, safety leadership actions and human performance principles. We are requiring our operational employees and independent contractors and their employees to go through orientation and training aligned with the International Association of Oil and Gas Producers Life Saving Rules, a program that also meets the operational safety requirements adopted by the American Petroleum Institute. We also involve employees from all operational levels in our safety program to provide input and suggested improvements to the overall safety program, recommend preventative measures based on reviewing vehicle and personnel incidents, safety and environmental audits at operational locations and participate in the audit and oversight of the Diamondback Hazard Communication Program.
From 2019 through 2023, we had no employee work-related fatalities. Our employee OSHA recordable cases, comprising work-related injuries and illnesses that require medical treatment beyond first aid, totaled three in 2023, down from six in 2022. Our employee total recordable incident rate (TRIR) was 0.30 in 2023 down from 0.68 in 2022, and lost-time incident rate (LTIR) was 0.10 in 2023 down from 0.23 in 2022. At December 31, 2023, we have a short term goal of maintaining an employee TRIR of 0.25 or less.
Training and Development
We support employees in pursuing training opportunities to expand their professional skills. Our internal course offerings in 2023 included a wide array of topics in addition to extensive safety and other compliance training sessions. Additionally, our people undergo training and education each year on regulatory compliance, industry standards and innovative opportunities to effectively manage the challenges of developing our resources. We have also implemented development programs that are designed to build leadership capabilities at all levels.
Our Facilities
Our corporate headquarters is located at the Fasken Center in Midland, Texas. We also lease additional office space in MidlandDallas, Texas and in Oklahoma City, Oklahoma. We believe that our facilities are adequate for our current operations.
Availability of Company Reports
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.diamondbackenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Form 10-KAnnual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. Reports filed or furnished with the SEC are also made available on its website at www.sec.gov.
ITEM 1A. RISK FACTORS
The nature of our business activities subjects us to certain hazards and risks. The following is a summary of some of the material risks relating to our business activities. Other risks are described in Item 1. “Business and Properties”Properties,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks we face. We could also face additional risks and uncertainties not currently known to the Companyus or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.
The following is a summary of the principal risks that could adversely affect our business, operations and financial results:
Risks Related to the Oil and Natural Gas Industry and Our Business
•Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas have in the past adversely affected, and may in the futurecontinue to adversely affect our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
•Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty credit risk.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:
the domestic and foreign supply of oil and natural gas;
the level of prices and expectations about future prices of oil and natural gas;
the level of global oil and natural gas exploration and production;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the price and quantity of foreign imports;
political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
speculative trading in crude oil and natural gas derivative contracts;
the level of consumer product demand;
weather conditions•The IRA and other natural disasters;
risks associated with operating drilling rigs;
technological advances affecting energy consumption;
relating to climate change could accelerate the price and availability of alternative fuels;
domestic and foreign governmental regulations and taxes;
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and
overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficulttransition to predict future oil and natural gas price movements with any certainty. During the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $26.19 per barrel, or Bbl, in February 2016
to a high of $110.62 per Bbl in September 2013. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. During 2017, WTI prices ranged from $42.48 to $60.46 per Bblcarbon economy and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On January 29, 2018, the WTI posted price for crude oil was $65.71 per Bbl and the Henry Hub spot market price of natural gas was $3.60 per MMBtu, representing increases of 9% and 3%, respectively, from the high of $60.46 per Bbl of oil and $3.71 per MMBtu for natural gas during 2017. If the prices of oil and natural gas decline,could impose new costs on our operations financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.
In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
Concerns over general economic, business or industry conditions may have a material and adverse effect on our results of operations, liquidityus.
•Climate change-related regulations, policies and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, may precipitate an economic slowdown. Concerns about global economic growthinitiatives may have another adverse impact on global financial markets and commodity prices. If the economic climate in the United Stateseffects, such as a greater potential for governmental investigations or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.litigation.
A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
Our development and exploration operations and our ability to complete acquisitions require substantial capital and we•We may be unable to obtain needed capital or financing on satisfactory terms or at all to fund our acquisitions or development activities, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2017, our total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $3.2 billion. Our 2018 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $1.3 billion to $1.5 billion, representing an increase of 60% over our 2017 capital budget. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and the senior notes.
We intend to finance our future capital expenditures with cash flow from operations, proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:
our proved reserves;
the volume of oil and natural gas we are able to produce from existing wells;
the prices at which our oil and natural gas are sold;
our ability to acquire, locate and produce economically new reserves; and
our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2018 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.
Our success depends on finding, developing or acquiring additional reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made, and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.production.
•Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings, and slow our growth.
There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:
recoverable reserves;
future oil and natural gas prices and their applicable differentials;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions, including our recently completed and pending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We may incur losses as a result of title defects in the properties in which we invest.invest may lead to losses.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.
Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. From inception through December 31, 2017, we drilled a total of 412 gross horizontal wells and 262 gross vertical wells and participated in an additional 61 gross horizontal wells and 18 gross vertical non-operated wells, of which 670 wells were completed as producing wells and 83 wells were in various stages of completion. If future wells or the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.
•Our identified potential drilling locations which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 3,800 gross (2,750 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage. As of December 31, 2017, only 168 of our gross identified potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, we have identified approximately 873 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Through December 31, 2017, we are the operator of or have participated in a total of 466 horizontal wells completed on our acreage, we cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. 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 oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our quarterly operating results.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2017, we had leases representing 22,913 net acres expiring in 2018, 19,670 net acres expiring in 2019, 20,219 net acres expiring in 2020, 719 net acres expiring in 2021 and no net acres expiring in 2022. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases expiring in 2018, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.
We have entered into fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options and may in the future enter into forward sale contracts or additional fixed price swap, fixed price basis swap derivatives or costless collars for a portion of our production. Although we have hedged a portion of our estimated 2018 and 2019 production, we may still be adversely affected by continuing and prolonged declines in the price of oil.
We use fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our oil and natural gas sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. Under the Company’s costless collar contracts, we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the call option price. The counterparty is required to make a payment
to us if the settlement price for any settlement period is less than the put option price. These contracts and any future economic hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase.
As of December 31, 2017, we had the following commodity contracts in place covering NYMEX WTI crude oil, Brent crude oil and NYMEX Henry Hub natural gas for the production period of January 2018 through December 2018:
crude oil swap contracts priced at a weighted average price of $51.10 WTI for 9,761,000 aggregate Bbls;
crude oil swap contracts priced at a weighted average price of $54.89 Brent for 1,830,000 aggregate Bbls;
crude oil basis swap contracts priced at a weighted average price of $0.88 for 5,475,000 aggregate Bbls for the spread between the WTI Midland price and the WTI Cushing price;
natural gas swap contracts priced at a weighted average price of $3.14 for 7,750,000 aggregate MMBtu; and
crude oil costless collars contracts with a floor price of $47.00 for 540,000 aggregate Bbls and a ceiling price of $56.34 for 270,000 aggregate Bbls.
We have crude oil swap contracts priced at a weighted average price of $49.82 WTI for 1,095,000 aggregate Bbls with a production period of January 2019 through December 2019. To the extent that the prices of oil and natural gas remain at current levels or decline further, we will not be able to economically hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.
Our derivative transactions expose us to counterparty credit risk.
Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.
•If production from our Permian Basin acreage decreases, due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which will result in deficiency payments to the counterparty and may have an adverse effect onadversely affect our operations.
We are a party to an agreement with Shell Trading (US) Company under which we are obligated to deliver specified quantities of oil to Shell Trading (US) Company. Our maximum delivery obligation under this agreement is 8,000 gross barrels per day. We have a one-time right to decrease the contract quantity by not more than 20% of the then-current quantity. This decreased quantity, if elected, would be effective for the remainder of the term of the agreement. If production from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under the oil purchase agreement, which may result in deficiency payments to the counterparty and may have an adverse effect on our operations.
•The inability of one or more of our customers to meet their obligations, or loss of one or more of our significant purchasers, may adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $73.0 million at December 31, 2017) and receivables from purchasers of our oil and natural gas production (approximately $158.6 million at December 31, 2017). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.
We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%) and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customer accounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.
Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.
•Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.11, $11.23 and $17.84 for the years ended December 31, 2017, 2016 and 2015, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2017, 2016 and 2015 was $321.9 million, $176.4 million and $216.1 million, respectively.
The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. Beginning December 31, 2009, we have used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.
Impairments on proved oil and natural gas properties of $245.5 million and $814.8 million were recorded for the years ended December 31, 2016 and 2015, respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Policies and Estimates–Method of accounting for oil and natural gas properties” for a more detailed description of our method of accounting.
Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. •Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves as of December 31, 2017, 2016 and 2015 (which include those attributable to Viper)•We are based on reports prepared by Ryder Scott, which conducted a well-by-well review of all our properties for the periods covered by its reserve reports using information provided by us. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
The estimates of reserves as of December 31, 2017, 2016 and 2015 included in this report were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods December 31, 2017, 2016 and 2015, respectively, in accordance with the SEC guidelines applicable to reserve estimates for such periods.
The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.
The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.
The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.
Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities–Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe because they have become uneconomic or otherwise.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Approximately 37.8% of our total estimated proved reserves as of December 31, 2017, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operatingour primary operations concentrated in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
All of our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays•If transportation or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
In addition to the geographic concentration of our producing properties described above, as of December 31, 2017, all of our proved reserves were attributable to the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%) and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customer accounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.
Our business operations have grown substantially since our initial public offering in October 2012 and we expect our business operations to continue to grow in the future. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
We have incurred losses from operations during certain periods since our inception and may do so in the future.
Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.
Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilitiescontrol, or rigs, equipment, raw materials, oil services or personnel are unavailable, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oil by truck to a pipeline for transportation. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.
•Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
Our oilexpensive and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitationsimpose restrictions on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See Item 1. “Business–Regulation” for a description of certain laws and regulations that affect us.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.
In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office,
have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For a more detailed discussion of state and local laws and initiatives concerning hydraulic fracturing, see “Items 1 and 2. Business and Properties–Regulation–Regulation of Hydraulic Fracturing.” We use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.
We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our
operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under the legislation, the Commodities Futures Trading Commission has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The Commodities Futures Trading Commission’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the Commodities Futures Trading Commission to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the Commodities Futures Trading Commission has indicated that it intends to appeal the court’s decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.
In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the Commodities Futures Trading Commission will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Recently enacted •U.S. tax legislation, as well as future U.S. tax legislationsincluding recently adopted IRA, may adverselynegatively affect ourbusiness, results of operations, financial condition and cash flow.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Ac, which we refer to as the Tax Act, that significantly reforms the Internal Revenue Code of 1986, as amended, which we refer to as the Code. Among other changes, the Tax Act (i) reduces the maximum U.S. corporate income tax rate from 35% to 21%, (ii) preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling, (iii) allows for immediate expensing of capital expenditures for tangible personal property for a period of time, (iv) modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations and (v) enacts new limitations regarding the deductibility of interest expense. The Tax Act is complex and far-reaching, and we cannot predict with certainty the resulting impact its enactment will have on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional
regulatory guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse effect on our business, results of operations, financial condition and cash flow.
In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.
Regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for the oil and natural gas we produce.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. While we are subject to certain federal greenhouse gas monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed greenhouse gas rules and regulations, see “Items 1 and 2. Business and Properties–Regulation–Environmental Regulation-Climate Change.”
At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully
insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Commission has used this authority to deny permits for waste disposal wells.
We dispose of large volumes of produced water gathered from our drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by owned disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the Natural Gas Act of 1938 exempts natural gas gathering facilities from regulation by the FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore are exempt from FERC’s jurisdiction under the Natural Gas Act of 1938. However, the distinction between FERC–regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.
We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.
We rely on a few key employees whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
•Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.
Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:
unusual or unexpected geological formations;
loss of drilling fluid circulation;
title problems;
facility or equipment malfunctions;
unexpected operational events;
shortages or delivery delays of equipment and services;
compliance with environmental and other governmental requirements; and
adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices
for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.
Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.
In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to
discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.
Increased costs of capital could adversely affect our business.
Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
We recorded stock-based compensation expense in 2017, 2016 and 2015, and we may incur substantial additional compensation expense related to our future grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.
As a result of outstanding stock-based compensation awards, for the years ended December 31, 2017, 2016 and 2015 we incurred $34.2 million, $33.5 million and $24.6 million, respectively, of stock based compensation expense, of which we capitalized $8.6 million, $7.1 million and $6.0 million respectively, pursuant to the full cost method of accounting for oil and natural gas properties. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and possible future incentive plans. These additional expenses could adversely
affect our net income. The future expense will be dependent upon the number of share-based awards issued and the fair value of the options or shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.
Loss of our information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
•A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist effortsbusiness and other armed conflicts involving the United States or other countries maycould adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. business.
We are subject to cyber security risks. •A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.
Risks Related to Our Indebtedness
•Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the senior notesour indebtedness, and we and our other indebtedness.
As of December 31, 2017, we had total long-term debt of $1.5 billion, including $1.0 billion outstanding under the 2024 senior notes and 2025 senior notes, and we had an unused borrowing base availability of $603.0 million under our revolving credit facility. On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% Senior Notes due 2025, which we refersubsidiaries may be able to as the new 2025 notes, asincur substantial additional notes under our existing indenture, and repaid $308.5 million of our outstanding borrowings under the revolving credit facility with the net proceeds from the issuance of our new 2025 notes. Immediately following the issuance of the new 2025 notes and the application of our net proceeds thereof, we had total long-term debt of $1.39 billion (including $1.3 billion attributable to all of our outstanding senior notes), our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility. As of December 31, 2017, Viper, one of our subsidiaries, had $93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. We mayindebtedness in the future incurfuture.
•Implementing our capital programs may require, under some circumstances, an increase in our total leverage through additional debt issuances, and any significant additional indebtednessreduction in availability under our revolving credit facility or inability to otherwise in order to make acquisitions, to developobtain financing for our properties or for other purposes. Our level of indebtedness could have important consequences to you and affect our operations in several ways, including the following:
our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to the senior notes, including any repurchase obligations that may arise thereunder;
a significant portion of our cash flows could be used to service the senior notes and our other indebtedness, which could reduce the funds available to us for operations and other purposes;
a high level of debt could increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry;
a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redeterminationcapital programs could require us to repay a portion of our then-outstanding bank borrowings;
a high level of debt could limit our ability to access the capital markets to raise capital on favorable terms;
a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.
A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering ofcurtail our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.expenditures.
•Restrictive covenants in certain of our revolving credit facility, the indentures governing the senior notesexisting and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.
Our revolving credit facility and the indentures governing our outstanding senior notes contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things:
incur or guarantee additional indebtedness;
make certain investments;
create additional liens;
sell or transfer assets;
issue preferred stock;
merge or consolidate with another entity;
pay dividends or make other distributions;
designate certain of•We depend on our subsidiaries as unrestricted subsidiaries;
create unrestricted subsidiaries;
engage in transactions with affiliates; and
enter into certain swap agreements.
In connection with the closing of Viper’s initial public offering on June 23, 2014, we entered into an amendment to our revolving credit facility, which modified certain provisions of our revolving credit facility to allow us, among other things, to designate one or more of our subsidiaries as “unrestricted subsidiaries” that are not subject to certain restrictions contained in the revolving credit facility. Under the amended revolving credit facility, we designated Viper, the general partner and Viper’s subsidiary as unrestricted subsidiaries, and upon such designation, they were automatically released from any and all obligations under the amended revolving credit facility, including the related guaranty, and all liens on the assets of, and the equity interests in, Viper, the general partner and Viper’s subsidiary under the amended revolving credit facility were automatically released. Further Viper, the general partner and Viper’s subsidiaries, Viper Energy Partners LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC), are designated as unrestricted subsidiaries under the indentures governing our outstanding senior notes.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in our revolving credit facility and the indentures governing our senior notes. In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
A breach of any of these restrictive covenants could result in default under our revolving credit facility. If default occurs, the lenders under our revolving credit facility may elect to declare all borrowings outstanding, together with accrued interestfor dividends and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.payments.
Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.
Availability under our revolving credit facility is currently subject to a borrowing base of $1.8 billion, of which we have elected a commitment amount of $1.0 billion. The borrowing base is subject to scheduled annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 2.97% on December 31, 2017. On January 29, 2018, we repaid $308.5 million of our outstanding borrowings under the revolving credit facility with the net proceeds from the issuance of our new 2025 notes. Immediately following the issuance of the new 2025 notes and the application of our net proceeds thereof, our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility. We expect to borrow under our revolving credit facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.
Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more
alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.
We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our revolving credit facility and the indentures governing our senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2017, our borrowing base under our revolving credit facility was set at $1.8 billion, of which we have elected a commitment amount of $1.0 billion and we had $397.0 million outstanding borrowings under this facility. As of December 31, 2017, Viper had $93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. Further, the indentures governing the senior notes allow us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indentures governing the senior notes also allow us to incur certain other additional secured debt and allows us to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.
•If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
•Borrowings under our and Viper’sViper LLC’s revolving credit facilities expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 2.97% on December 31, 2017. Viper’s weighted average interest rate on borrowings from its revolving credit facility was 3.19% during the year ended December 31, 2017. As of December 31, 2017, Viper had $93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
Risks Related to Our Common Stock
•The corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.
•The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors, and there is no guarantee that we will pay any dividends on or repurchases of our common stock in the future or at levels anticipated by our stockholders.
•A change of control could limit our use of net operating losses.
•We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
•Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.
Risks Related to the Pending Endeavor Acquisition
•Our ability to complete the Endeavor Acquisition is subject to various closing conditions, including approval by our stockholders and regulatory clearance, which may impose conditions that could adversely affect us or cause the Endeavor Acquisition not to be completed.
•The termination of the Merger Agreement could negatively impact our business or result in our having to pay a termination fee.
•Whether or not the Endeavor Acquisition is completed, the announcement and pendency of the Endeavor Acquisition could cause disruptions in our business.
•Combining our business with Endeavor’s may be more difficult, costly or time-consuming than expected and the combined company may fail to realize the anticipated benefits of the Endeavor Acquisition.
•We also expect to incur significant additional indebtedness in connection with the Endeavor Acquisition, which indebtedness may limit our operating or financial flexibility relative to our current position and make it difficult to satisfy our obligations with respect to our other indebtedness.
•The market value of our common stock could decline if large amounts of our common stock are sold following the Endeavor Acquisition.
•Following the closing of the Endeavor Acquisition, the Endeavor Stockholders will have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders.
Risks Related to the Oil and Natural Gas Industry and Our Business
Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including the domestic and foreign supply of oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports; political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia; the potential impact of the war in Ukraine and the Israel-Hamas War on the global energy markets and macroeconomic conditions; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; the ability of members of the OPEC+ to agree to and maintain oil price and production controls; speculative trading in crude oil and natural gas derivative contracts; the level of consumer product demand; extreme weather conditions and other natural disasters; risks associated with operating drilling rigs; technological advances affecting energy consumption; the price and availability of alternative fuels; domestic and foreign governmental regulations and taxes, including the Biden Administration’s energy and environmental policies; global or national health concerns, including the outbreak of pandemic or contagious disease; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and overall domestic and global economic conditions. Our results of operations may also be adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2023, 2022 and 2021, NYMEX WTI prices ranged from $47.62 to $123.70 per Bbl and the NYMEX Henry Hub price of natural gas ranged from $1.99 to $9.68 per MMBtu. If the prices of oil and natural gas decline, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.
We expect to maintain our fourth quarter 2023 production levels in 2024. We cannot reasonably predict whether production levels will remain at current levels or the full extent of the impact of the events above and any subsequent recovery may have on our industry and our business.
If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows will be adversely impacted. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to conduct additional exploration and development activities.
Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases andmayexpose us to other risks, including counterparty credit risk.
We use commodity price derivatives, including swaps, basis swaps, swaptions, roll hedges, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil, natural gas liquids and natural gas sales. Currently, we have hedged a portion of our estimated 2024 and 2025 production. To the extent that the prices of oil, natural gas liquids and natural gas remain at current levels or decline further, we may not be able to economically hedge additional future production at the same level as our current commodity price derivatives, and our results of operations and financial condition may be negatively impacted. While these commodity price derivatives are intended to mitigate risk from commodity price volatility, we may be prevented from fully realizing the benefits of increases in the prices of oil, natural gas liquids and natural gas above the price levels of the commodity price derivatives used to manage price risk.
At settlement, market prices for commodities may exceed the contract prices in our commodity price derivatives agreements, resulting in our need to make significant cash payments to our counterparties. Further, by using commodity derivative instruments, we expose ourselves to credit risk if we are in a positive position at contract settlement and the counterparty fails to perform under the terms of the derivative contract. We do not require collateral from our counterparties.
The IRA and other risks relating to climate change could accelerate the transition to a low carbon economy and could impose new costs on our operations that may have a material and adverse effect on us.
Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been increasingly focused on climate change matters in recent years. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in; (i) the enactment of climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures; (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); (iii) increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and (iv) development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.
Any of these developments may reduce the demand for products manufactured with (or powered by) hydrocarbons and the demand for, and in turn the prices of, the oil and natural gas that we produce and sell, which would likely have a material adverse impact on us.
If any of these developments reduce the desirability of participating in the oilfield services, midstream or downstream portions of the oil and gas industry, then these developments may also reduce the availability to us of necessary third-party services and facilities that we rely on, which could increase our operational costs and adversely affect our ability to explore for, produce, transport and process oil and natural gas and successfully carry out our business and financial strategy. The enactment of climate change-related regulations, policies and initiatives may also result in increases in our compliance costs and other operating costs and have other adverse effects, such as a greater potential for governmental investigations or litigation.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. For example, the Infrastructure Investment and Jobs Act and the IRA include billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration. Also, the EPA has proposed ambitious rules to reduce harmful air pollutant emissions, including greenhouse gases, from light-, medium-, and heavy-duty vehicles beginning in model year 2027. These incentives and regulations could accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell and adversely impact our business. In addition, the IRA imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge, which could increase our operating costs and thereby adversely impact our business, financial condition and cash flows.
In addition to potentially reducing demand for our oil and natural gas and potentially reducing the availability of oilfield services and midstream and downstream customers, any of these developments may also create reputational risks associated with the exploration for, and production of, hydrocarbons, which may adversely affect the availability and cost to us of capital. For example, a number of prominent investors have publicly announced their intention to no longer invest in the oil and gas sector in response to concerns related to climate change, and other financial institutions and investors may decide to do likewise in the future. If financial institutions and other investors refuse to invest in or provide capital to the oil and gas sector in the future because of these reputational risks, that could result in capital being unavailable to us, or only at significantly increased costs.
For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, please see the section entitled Items 1 and 2. Business and Properties—Regulation—Climate Change of this report.
Continuing political and social concerns relating to climate change may result in significant litigation and related expenses.
Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect us. For example, shareholder activism has recently been increasing in our industry, and shareholders may attempt to effect changes to our business or governance to deal with climate change-related issues, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise, which may result in significant management distraction and potentially significant expense.
Additionally, cities, counties, and other governmental entities in several states in the U.S. have filed lawsuits against energy companies seeking damages allegedly associated with climate change. Similar lawsuits may be filed in other jurisdictions. If any such lawsuits were to be filed against us, we could incur substantial legal defense costs and, if any such litigation were adversely determined, we could incur substantial damages.
Any of these climate change-related litigation risks could result in unexpected costs, negative sentiments about our company, disruptions in our operations, and increases to our operating expenses, which in turn could have an adverse effect on our business, financial condition and results of operations.
Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks.
We have developed, and will continue to develop, targets related to our environmental, social and governance (“ESG”) initiatives, including our emissions reduction targets and strategy. Statements in this and other reports we file with the SEC and other public statements related to these initiatives reflect our current plans and expectations and are not a guarantee the targets will be achieved or achieved on the currently anticipated timeline. Our ability to achieve our ESG targets, including emissions reductions, is subject to numerous factors and conditions, some of which are outside of our control, and failure to achieve our announced targets or comply with ethical, environmental or other standards, including reporting standards, may expose us to government enforcement actions or private litigation and adversely impact our business. Further, our continuing efforts to research, establish, accomplish and accurately report on these targets may create additional operational risks and expenses and expose us to reputational, legal and other risks.
ESG expectations, including both the matters in focus and the management of such matters, continue to evolve rapidly. For example, in addition to climate change, there is increasing attention on topics such as diversity and inclusion, human rights, and human and natural capital, in companies’ own operations as well as their supply chains. In addition, perspectives on the efficacy of ESG considerations continue to evolve, and we cannot currently predict how regulators’, investors’ and other stakeholders’ views on ESG matters may affect the regulatory and investment landscape and affect our business, financial condition, and results of operations. If we do not, or are perceived to not, adapt or comply with investor or stakeholder expectations and standards on ESG matters, we may suffer from reputational damage and our business, financial condition and results of operations could be materially and adversely affected. Any reputational damage associated with ESG factors may also adversely impact our ability to recruit and retain employees and customers.
In March 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related risks and other information. To the extent this rule is finalized as proposed, we and/or our customers could incur increased costs related to the assessment and disclosure of climate-related information. Enhanced climate disclosure requirements could also accelerate any trend by certain stakeholders and capital providers to restrict or seek more stringent conditions with respect to their financing of certain carbon intensive sectors.
Investor and regulatory focus on ESG matters continues to increase. If our ESG initiatives do not meet our investors’ or other stakeholders’ evolving expectations and standards, investment in our stock may be viewed as less attractive and our reputation, contractual, employment and other business relationships may be adversely impacted.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive and to maintain the production in paying quantities, and if we are unsuccessful in drilling such wells and maintaining such production, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
Our development and exploration operations and our ability to complete acquisitions require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2023, our total capital expenditures, including expenditures for drilling, completion, infrastructure and additions to midstream assets, were approximately $2.7 billion. Our 2024 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $2.30 billion to $2.55 billion, representing a decrease of 10% from our 2023 capital expenditures. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and our senior notes.
We intend to finance our future capital expenditures with cash flow from operations, while future acquisitions may also be funded from operations as well as proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including our proved reserves; the volume of oil and natural gas we are able to produce from existing wells; the prices at which our oil and natural gas are sold; our ability to acquire, locate and produce economically new reserves; and our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2024 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements or our costs of capital increase, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.
Our success depends on finding, developing or acquiring additional reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding and development costs for additional reserves could also increase.
Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings and slow our growth.
There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs, and potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, including title defects or environmental issues, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If these acquisitions include geographic regions in which we do not currently operate, we could be subject to unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
Any of these factors could have a material adverse effect on our financial condition and results of operations. Our financial position and results of operations may also fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs.
As of December 31, 2023, we have approximately 7,905 gross (5,826 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $50.00 per Bbl WTI. As of December 31, 2023, only 802 of our gross identified economic potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, unusual or unexpected geological formations, title problems, facility or equipment malfunctions, unexpected operational events, inclement weather, environmental and other regulatory requirements and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, as of December 31, 2023, we have identified approximately 2,561 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations,
our drilling success rate may decline and materially harm our business. Through December 31, 2023, we are the operator of, have participated in, or have acquired working interest in a total of 3,356 horizontal producing wells completed on our acreage. We cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. 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 oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. Any non-renewal or other loss of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.
If production from our Permian Basin acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contracts, which will result in deficiency payments to the counterparty and may have an adverse effect on our operations.
We are a party to long-term crude oil agreements under which, subject to certain terms and conditions, we are obligated to deliver specified quantities of oil to our counterparties. Our maximum delivery obligation under these agreements varies for different periods and depends in some cases upon certain conditions beyond our control. If production from our Permian Basin acreage decreases due to reduced developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under our oil purchase agreements, which may result in deficiency payments to certain counterparties or a default under such agreements and may have an adverse effect on our company.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $122 million at December 31, 2023) and receivables from purchasers of our oil and natural gas production (approximately $654 million at December 31, 2023). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.
We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. See Items 1 and 2. Business and Properties—Marketing and Customers of this report for additional information regarding these customers. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic and other conditions. We do not require our customers to post collateral. Under certain circumstances, the revenue due to them can be offset by any unpaid receivables. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.
Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment.
The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.
Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.
The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil reserves.
The present value of future net cash flows from our proved reserves, or standardized measure may not represent the current market value of our estimated proved oil reserves. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Approximately 31% of our total estimated proved reserves as of December 31, 2023, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling and completion operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks (including weather-related risks) associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
Our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids, and extreme weather conditions and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities.
Extreme regional weather events may occur that can affect our suppliers or customers, which could adversely affect us. For example, a significant hurricane or similar weather event could damage refining and other oil and natural gas-related facilities on the Gulf Coast of Texas and Louisiana, which (if significant enough) could limit the availability of gathering and transportation facilities across Texas and could then cause production in the Permian Basin (including potentially our production) to be curtailed or shut in or (in the case of natural gas) flared. Climate change may also increase the frequency and severity of significant weather events over time. Further, any increase in flaring of our natural gas production due to weather-related events or otherwise could make it difficult for us to achieve our publicly-announced sustainability and emissions reduction targets, which could expose us to reputational risks and adversely impact our contractual and other business relationships. Any of the above-referenced events could have a material adverse effect on us and our production volumes (and therefore on our financial condition and results of operations).
In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
In addition to the geographic concentration of our producing properties described above, as of December 31, 2023, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including those discussed. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See Items 1 and 2. Business and Properties—Marketing and Customers of this report for additional information regarding these customers. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operators of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could
delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Also, in 2021, the Texas Legislature directed the Texas Railroad Commission to adopt rules encouraging fluid oil and gas waste recycling. In October 2023, the Commission announced draft amendments to its water protection rules to, among other things, encourage waste recycling. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
Recent regulatory restrictions on the disposal of produced water and additional monitoring and reporting requirements related to existing and new produced water disposal wells in the Permian Basin to stem rising seismic activity and earthquakes could increase our operating costs and adversely impact our business, results of operations and financial condition.
In September 2021, the Texas Railroad Commission curtailed the amount of produced water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has since indefinitely suspended some permits there and expanded the restrictions to other areas. These actions were taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S. and local seismologists to wastewater disposal in oil fields. The Texas Railroad Commission has since adopted rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. These restrictions and additional monitoring and reporting requirements related to existing and new produced water and produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or dispose of it by other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.
Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve developing and utilizing the latest drilling and completion techniques. Risks that we face while drilling include, but are not limited to, spacing of wells to maximize economic return; landing our well bore in the desired drilling zone; staying in the desired drilling zone while drilling horizontally through the formation; running our casing the entire length of the well bore; and being able to run tools and other equipment consistently through the horizontal well bore.
Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages; run tools the entire length of the well bore during completion operations; successfully clean out the well bore after completion of the final fracture stimulation stage; and prevent unintentional communication with other wells.
Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. We do not control third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.
Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Further, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See Items 1 and 2. Business and Properties—Regulation of this report for a detailed description of certain laws and regulations that affect us.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered, such as the recent designation of lesser prairie chickens in southwestern Texas as endangered, could cause us to incur increased costs arising
from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.
The Dodd-Frank Act established federal oversight of the over-the-counter derivatives market and entities, including us, that participate in that market. The Dodd-Frank Act required the Commodity Futures Trading Commission (CFTC), the SEC, and certain federal regulators of financial institutions (Prudential Regulators), to adopt rules or regulations implementing the Dodd-Frank Act. The Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued a number of rules, including rules requiring clearing of certain swaps through registered clearing facilities (Mandatory Clearing Rule), requiring the posting of collateral for uncleared swaps (Margin Rule) and imposing position limits (Position Limit Rule). There are exceptions, subject to meeting certain filing, recordkeeping and reporting requirements, to the Mandatory Clearing Rule, the Margin Rule and the Position Limit Rule.
We qualify for the “end user” exception to the Mandatory Clearing Rule and the “non-financial end user” exception to the Margin Rule and we believe that the majority, if not all, of our hedging activities qualify for the “bona fide hedging transaction or position” exception to the Position Limit Rule. We intend to satisfy the applicable filing, recordkeeping and reporting requirements to use these exceptions, so we do not expect to be directly affected by any of such rules. However, most if not all of our swap counterparties will be subject to mandatory clearing and collateral requirements in connection with their hedging activities with other counterparties that do not qualify for exceptions to these rules, which could significantly increase the cost of our derivative contracts or reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business.
In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (collectively, Foreign Regulations), which may apply to our transactions with counterparties subject to such Foreign Regulations (Foreign Counterparties). The Foreign Regulations, the Dodd-Frank Act, the rules which have been adopted and not vacated and other regulations could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act, the Foreign Regulations or other regulations, our results of operations and cash flows may become more volatile and less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
U.S. tax legislation may adversely affect ourbusiness, results of operations, financial condition and cash flow.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.
On August 16, 2022, President Biden signed into law the IRA, which, among other changes, imposes a 15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) as well as an excise tax of 1% on the fair market value of certain public company stock repurchases for tax years beginning after December 31, 2022. If we are or become subject to CAMT, our cash obligations for U.S. federal income taxes could be significantly accelerated.To the extent the 1% excise tax applies to repurchases of shares under our common stock repurchase program, the number of shares we repurchase and our cash flow may be affected.
The U.S. Treasury Department, the Internal Revenue Service and other standard-setting bodies are expected to issue guidance on how the CAMT, stock buyback excise tax and other provisions of the IRA will be applied or otherwise administered that may differ from our interpretations. We continue to evaluate the IRA and its effect on our financial results and operating cash flow.
We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.
We rely on a few key employees whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our operations. We do not have employment agreements with our executives and may not be able to assure their retention. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.
In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability
to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
Since hydraulic fracturing activities are part of our operations, we maintain insurance to protect against claims made for bodily injury and property damage, and that insurance includes coverage for clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have limited coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
We own interests in certain pipeline projects and other joint ventures, and we may in the future enter into additional joint ventures, and our control of such entities is limited by provisions of the governing documents of such entities and by our percentage ownership in such entities.
We have ownership interests in several joint ventures, including the EPIC, Wink to Webster, BANGL, WTG and Deep Blue joint ventures, and we may enter into other similar arrangements in the future. While we own equity interests and have certain voting rights with respect to our ownership interest, we do not control our joint ventures. We have limited ability to influence the business decisions of these entities, and it may therefore be difficult or impossible for us to cause the joint venture to take actions that we believe would be in our or the relevant joint venture’s best interests. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not control. In addition, our joint venture partners may not satisfy their financial obligations to the joint venture and may have economic, business or legal interests or goals that are inconsistent with ours, or those of the joint venture.
We are also unable to control the amount of cash we receive from the operation of these entities. Further, certain of these joint ventures have incurred substantial debt and servicing such debt or complying with debt covenants may limit the ability of the joint ventures to make distributions to us and the other joint venture partners. These joint ventures also have internal control environments independent of our oversight and review. If our joint venture partners have control deficiencies in their accounting or financial reporting environments, it may result in inaccuracies in the reporting for our percentage of the financial results of the joint venture.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.
We are heavily dependent on electrical power, internet and telecommunications infrastructure and our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business.
We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
As an exploration and production company, we rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or externally hosted hardware and software platforms, to (i) estimate our oil and natural gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, transportation, pipelines and other related activities and (iv) communicate with our employees and vendors, suppliers and other third parties. Further, our reliance on technology has increased due to the increased use of personal devices, remote communications and work-from-home or hybrid work practices that evolved in response to the COVID-19 pandemic and became a common business practice thereafter.
Risks from cybersecurity threats have not materially affected, and are not currently anticipated to materially affect our company, including our business strategy, results of operations and financial condition. However, our systems and networks, and those of our vendors, service providers and other third party providers, may become the target of cybersecurity attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. If any of these security breaches were to occur, we could suffer disruptions to our normal operations, including our exploration, completion, production and corporate functions, which could materially and adversely affect us in a variety of ways, including, but not limited to, unauthorized access to, and release of, our business data, reserves information, strategic information or other sensitive or proprietary information, which could have a material and adverse effect on our ability to compete for oil and gas resources, or reduce our competitive advantage over other companies; data corruption, communication interruption, or other operational disruptions during our drilling activities, which could result in our failure to reach the intended target or a drilling incident; data corruption or operational disruptions of our production-related infrastructure, which could result in loss of production or accidental discharges; unauthorized access to, and release of, personal information of our employees, vendors, service providers or other third parties, which could expose us to allegations that we did not sufficiently protect such information; a cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt our operations; a cybersecurity attack on third-party gathering, transportation, processing, fractionation, refining or other facilities, which could result in reduced demand for our production or delay or prevent us from transporting and marketing our production, in either case resulting in a loss of revenues; a cybersecurity attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues; a deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory enforcement actions, fines or penalties; a cybersecurity attack on a communications network or power grid, which could cause operational disruptions resulting in a loss of revenues; and a cybersecurity attack on our automated and surveillance systems, which could cause a loss of production and potential environmental hazards.
We have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threat. We have engaged third-party consultants to conduct penetration testing and risk assessments. Our
cybersecurity governance program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration. Such measures, however, cannot entirely eliminate cybersecurity threats and the controls, procedures and protections we have implemented and invested in may prove to be ineffective. We maintain specialized insurance for possible liability resulting from a cyberattack on our assets, however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Risks Related to Our Indebtedness
References in this section to “us, “we” or “our” shall mean Diamondback Energy, Inc. and Diamondback E&P LLC, collectively, unless otherwise specified.
Implementing our capital programs may require, under some circumstances, an increase in our total leverage through additional debt issuances, and any significant reduction in availability under our revolving credit facility or inability to otherwise obtain financing for our capital programs could require us to curtail our capital expenditures.
We have historically relied on availability under our revolving credit facility to fund a portion of our capital expenditures. We expect that we will continue to fund a portion of our capital expenditures with borrowings under the revolving credit facility, cash flow from operations and the proceeds from debt and equity offerings. In the past, we have created availability under the revolving credit facility by repaying outstanding borrowings with the proceeds from debt or equity offerings. We cannot assure you that we will choose to or be able to access the capital markets to repay any such future borrowings. Instead, we may be required or choose to finance our capital expenditures through additional debt issuances, which would increase our total amount of debt outstanding. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could limit our ability to fund our drilling activities and acquisitions or otherwise finance the capital expenditures necessary to replace our reserves.
Restrictive covenants in certain of our existing and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.
Certain of our debt instruments contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create liens; sell or transfer assets; issue preferred stock; merge or consolidate with another entity; pay dividends or make other distributions; create unrestricted subsidiaries; and engage in transactions with affiliates. A breach of any of these restrictive covenants could result in default under the applicable debt instrument.
We and our subsidiaries may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants and financial covenants contained in our and our subsidiaries’ debt instruments. As an example, our revolving credit facility requires us to maintain a total net debt to capitalization ratio. The requirement that we and our subsidiaries comply with these provisions may materially adversely affect our and our subsidiaries ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
If a default occurs under our revolving credit facility, the lenders thereunder may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.
Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.
Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. If we are unable to generate sufficient cash flow to service our debt, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining
additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.
We depend on our subsidiaries for dividends and other payments.
As a holding company, we depend on our subsidiaries for dividends and other payments. We are a legal entity separate and distinct from our operating subsidiaries. There are statutory and regulatory limitations on the payment of dividends. If our subsidiaries are unable to make dividend payments to us and sufficient cash or liquidity is not otherwise available, we may not be able to make dividend payments to our stockholders or principal and interest payments on our outstanding indebtedness.
We and our subsidiaries may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our and our subsidiaries’ revolving credit facilities and the indentures restrict, but in each case do not completely prohibit, us from doing so. Further, the indentures governing our and our subsidiaries’ notes allow us to issue additional notes, incur certain other additional debt and to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
Borrowings under our and Viper LLC’s revolving credit facilities expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our and Viper LLC’s revolving credit facilities. The terms of our and Viper LLC’s revolving credit facilities provide for interest on borrowings at a floating rate equal to an alternate base rate tied to the secured overnight financing rate (“SOFR”). SOFR tends to fluctuate based on multiple factors, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks and general economic conditions. From time to time, we use interest rate swaps to reduce interest rate exposure with respect to our fixed and/or floating rate debt. The weighted average interest rate on borrowings under our revolving credit facility was 6.31% during the year ended December 31, 2023. Viper LLC’s weighted average interest rate on borrowings from its revolving credit facility was 7.41% during the year ended December 31, 2023. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
Risks Related to Our Common Stock
The corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.
Subject to the limitations of applicable law, our certificate of incorporation, among other things:
permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;
permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.
These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.
We have engaged in transactions with our affiliatesThe declaration of base and expect to do so in the future. The terms of such transactionsvariable dividends and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.
In the past, we have engaged in transactions with affiliated companies and may do so again in the future. These transactions, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests.
If the pricerepurchases of our common stock fluctuates significantly, your investment could lose value.
Although our common stock is listed on the Nasdaq Select Global Market, we cannot assure you that an active public market will continue for our common stock. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:
our quarterly or annual operating results;
changes in our earnings estimates;
investment recommendations by securities analysts following our business or our industry;
additions or departures of key personnel;
changes in the business, earnings estimates or market perceptions of our competitors;
our failure to achieve operating results consistent with securities analysts’ projections;
changes in industry, general market or economic conditions; and
announcements of legislative or regulatory changes.
The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur
without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.
Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.
Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of such shares, or the perception that such sales may occur, could impair our ability to raise capital through the sale of additional common or preferred stock. Except for any shares purchased by our affiliates, all of the shares of common stock sold in our initial public offering and our subsequent equity offerings are freely tradable. In the event that one or more of our stockholders sells a substantial amount of our common stock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.
The declaration of dividends on our common stock iseach within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
On February 13, 2018, we announced that we are initiating an annual cash dividend in the amount of $0.50 per share of our common stock payable quarterly beginning with the first quarter of 2018.
The decision to pay this first dividend or any future base and variable dividends however, is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, whether base or variable, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.
In September 2021, our board of directors approved a stock repurchase program to acquire up to $2.0 billion of our outstanding common stock, and on July 28, 2022, approved an increase in the repurchase program to $4.0 billion. We may be limited in our ability to repurchase shares of our common stock by various governmental laws, rules and regulations which prevent us from purchasing our common stock during periods when we are in possession of material non-public information. Through December 31, 2023, approximately $2.4 billion has been repurchased through the repurchase program. Even though this program is in place, we may not repurchase any shares through the program and any such repurchases are completely within the discretion of our board of directors. In addition, the stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time. Any elimination of, or reduction in, the Company’s base or variable dividend or common stock repurchase program could adversely affect the total return of an investment in and have a material adverse effect on the market price of our common stock.
Beginning in the first quarter of 2024, our board of directors approved a reduction to our return of capital commitment to at least 50% from 75% of free cash flow to be distributed quarterly to our stockholders in the primary form of a base dividend with additional return of capital expected to be in the form of a variable dividend and through our stock repurchase program. The amount of cash available to return to our stockholders, if any, can vary significantly from quarter to quarter for a number of reasons, including commodity prices, liquidity, debt levels, capital resources and other factors. The price of our common stock may deteriorate if we are unable to meet investor expectations with respect to the timing and amount of our return of capital commitment to our stockholders, and such deterioration may be material.
A change of control could limit our use of net operating losses.losses and certain other tax attributes.
As of December 31, 2017, we had a net operating loss, or NOL, carry forward of approximately $357.0 million for federal income tax purposes. If we were to experience an “ownership change,” as determined underUnder Section 382 of the Internal Revenue Code ourof 1986, as amended (the “Code”), a corporation that experiences an “ownership change” (as defined in the Code) may be subject to limitations on its ability to offset taxable income arising after the ownership change with NOLsnet operating losses (“NOLs”) or tax credits generated prior to the ownership change would be limited, possibly substantially.change. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will occuroccurs if there is a cumulative increase in ourthe ownership of a corporation’s stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period. An ownership change would establish an annual limitation on the amount of a corporation’s pre-change NOLs or tax credits that could be utilized to offset taxable income in any future taxable year. The amount of the limitation is generally equal to the value of the corporation’s stock immediately prior to the ownership change multiplied by an interest rate, referred
If securities or industry analysts doto as the long-term tax-exempt rate, periodically promulgated by the IRS. This limitation, however, may be significantly increased if there is “net unrealized built-in gain” in the assets of the corporation undergoing the ownership change.
As of December 31, 2023, we had an NOL carryforward of approximately $590 million and tax credits of $4 million for U.S. federal income tax purposes, principally consisting of tax attributes acquired from QEP and Rattler. As a result of ownership changes for Diamondback Energy, Inc., QEP and Rattler, which occurred in connection with the acquisition of QEP and the Rattler Merger, our NOLs and other carryforwards, including those acquired from QEP and Rattler, are subject to an annual limitation under Section 382 of the Code. However, we have determined that our fair market value and our net unrealized built-in gain position resulted in a significant increase in our Section 382 limits. Accordingly, we believe that the application of Section 382 of the Code as a result of these ownership changes will not publish research or reports abouthave a material adverse effect on our business, if they adversely change their recommendations regardingability to utilize our NOLs and credits.
Future changes in our stock or if our operating results do not meet their expectations, our stock priceownership, however, could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibilityresult in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or morean additional ownership change under Section 382 of the analysts who coverCode. Any such ownership change may limit our company downgrade our stockability to offset taxable income arising after such an ownership change with NOLs or if our operating results do not meet their expectations, our stock price could decline.other tax attributes generated prior to such an ownership change, possibly substantially.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of theour company, which could adversely affect the price of our common stock.
The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:
including provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;
limitations on the ability of our stockholders to call a special meeting and act by written consent;
the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors;
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and
the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.
These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.
Risks Related to the pending Endeavor Acquisition
Our ability to complete the Endeavor Acquisition is subject to various closing conditions, including approval by our stockholders and regulatory clearance, which may impose conditions that could adversely affect us or cause the Endeavor Acquisition not to be completed.
On February 11, 2024, we entered into the Merger Agreement to acquire Endeavor. The Endeavor Acquisition is subject to a number of conditions to closing as specified in the Merger Agreement. These closing conditions include, among others, (i) the approval of the issuance of our common stock in the first merger by our stockholders; (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (iii) the absence of any injunction, order, decree or law preventing, prohibiting or making illegal the consummation of the first merger; (iv) the authorization for listing on the Nasdaq of the shares of our common stock to be issued in the first merger; (v) with respect to each party, (a) the accuracy of the other party’s representations and warranties, subject to specified materiality
qualifications, (b) compliance by the other party with its covenants in the Merger Agreement in all material respects, and (c) the absence of a “Material Adverse Effect” (as defined in the Merger Agreement) with respect to the other party since the date of the Merger Agreement that is continuing; and (vi) in the case of Endeavor, the receipt of an opinion of tax counsel that the Endeavor Acquisition will qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended.
No assurance can be given that the required stockholder approval and regulatory clearance will be obtained or that the other required conditions to closing will be satisfied, and, if all required approvals and regulatory clearance are obtained and the required conditions are satisfied, no assurance can be given as to the terms, conditions and timing of such approvals and clearance, including whether any required conditions will materially adversely affect the combined company following the acquisition. Any delay in completing the Endeavor Acquisition could cause the combined company not to realize, or to be delayed in realizing, some or all of the benefits that we and Endeavor expect to achieve if the Endeavor Acquisition is successfully completed within its expected time frame. We can provide no assurance that these conditions will not result in the abandonment or delay of the acquisition. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations and the trading price of our common stock.
The termination of the Merger Agreement could negatively impact our business or result in our having to pay a termination fee.
If the Endeavor Acquisition is not completed for any reason, including as a result of a failure to obtain the required approval from our stockholders, our ongoing business may be adversely affected and, without realizing any of the expected benefits of having completed the Endeavor Acquisition, we would be subject to a number of risks, including the following: (i) we may experience negative reactions from the financial markets, including negative impacts on our stock price; (ii) we may experience negative reactions from our commercial and vendor partners and employees; and (iii) we will be required to pay our costs relating to the Endeavor Acquisition, such as financial advisory, legal, financing and accounting costs and associated fees and expenses, whether or not the Endeavor Acquisition is completed.
Additionally, we are required to pay Endeavor a termination fee of $1.4 billion if the Merger Agreement is terminated by (i) Endeavor because our board of directors has made an adverse change to its recommendation that the our stockholders vote in favor of the issuance of our common stock in the Endeavor Acquisition or (ii) if either party terminates the Merger Agreement because our stockholders fail to approve the issuance of our common stock in the Endeavor Acquisition and, immediately prior to the failed vote, Endeavor would have been entitled to terminate the Merger Agreement because our board of directors had made an adverse change to its recommendation in favor of the issuance of our common stock in the Endeavor Acquisition. If the Merger Agreement is terminated under certain specified circumstances and, within 12 months following such termination, we consummate or enter into an alternative acquisition transaction, we are required to pay the termination fee to Endeavor. Additionally, if the Merger Agreement is terminated because our stockholders fail to approve the issuance of our stock in the Endeavor Acquisition and the termination fee is not payable in connection with such termination, we are required to reimburse Endeavor for its transaction related expenses, subject to a cap of $260 million. The payment of this reimbursement will reduce any termination fee that is subsequently payable by us.
Whether or not the Endeavor Acquisition is completed, the announcement and pendency of the Endeavor Acquisition could cause disruptions in our business, which could have an adverse effect on our business and financial results.
Whether or not the Endeavor Acquisition is completed, the announcement and pendency of the Endeavor Acquisition could cause disruptions in our business. Specifically: (i) our and Endeavor’s current and prospective employees will experience uncertainty about their future roles with the combined company, which might adversely affect the two companies’ abilities to retain key managers and other employees; (ii) uncertainty regarding the completion of the Endeavor Acquisition may cause our and Endeavor’s commercial and vendor partners or others that deal with us or Endeavor to delay or defer certain business decisions or to decide to seek to terminate, change or renegotiate their relationships with us or Endeavor, which could negatively affect our respective revenues, earnings and cash flows; (iii) the Merger Agreement restricts us and our subsidiaries from taking specified actions during the pendency of the Merger without Endeavor’s consent, which may prevent us from making appropriate changes to our business or organizational structure or prevent us from pursuing attractive business opportunities or strategic transactions that may arise prior to the completion of the Endeavor Acquisition; and (iv) the attention of our and Endeavor’s management may be directed toward the completion of the Endeavor Acquisition as well as integration planning, which could otherwise have been devoted to day-to-day operations or to other opportunities that may have been beneficial to our business.
We have and will continue to divert significant management resources in an effort to complete the Endeavor Acquisition and are subject to restrictions contained in the Merger Agreement on the conduct of our business. If the Endeavor Acquisition is not completed, we will have incurred significant costs, including the diversion of management resources, for which we will have received little or no benefit.
Combining our business with Endeavor’s may be more difficult, costly or time-consuming than expected and the combined company may fail to realize the anticipated benefits of the Endeavor Acquisition, which may adversely affect the combined company’s business results and negatively affect the value of the combined company’s common stock.
The success of the Endeavor Acquisition will depend on, among other things, the ability of the two companies to combine their businesses in a manner that facilitates growth opportunities and realizes expected cost savings. The combined company may encounter difficulties in integrating our and Endeavor’s businesses and realizing the anticipated benefits of the Endeavor Acquisition. The combined company must achieve the anticipated improvement in free cash flow generation and returns and achieve the planned cost savings without adversely affecting current revenues or compromising the disciplined investment philosophy for future growth. If the combined company is not able to successfully achieve these objectives, the anticipated benefits of the Endeavor Acquisition may not be realized fully, or at all, or may take longer to realize than expected.
The Endeavor Acquisition involves the combination of two companies which currently operate, and until the completion of the Endeavor Acquisition will continue to operate, as independent companies. There can be no assurances that our respective businesses can be integrated successfully. It is possible that the integration process could result in the loss of key employees from both companies; the loss of commercial and vendor partners; the disruption of our, Endeavor’s or both companies’ ongoing businesses; inconsistencies in standards, controls, procedures and policies; unexpected integration issues; higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. The combined company will be required to devote management attention and resources to integrating its business practices and operations, and prior to the Endeavor Acquisition, management attention and resources will be required to plan for such integration. An inability to realize the full extent of the anticipated benefits of the Endeavor Acquisition and the other transactions contemplated by the Merger Agreement, as well as any delays encountered in the integration process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may adversely affect the value of the common stock of the combined company. In addition, the actual integration may result in additional and unforeseen expenses, and the anticipated benefits of the integration plan may not be realized. There are a large number of processes, policies, procedures, operations and technologies and systems that must be integrated in connection with the Endeavor Acquisition and the integration of Endeavor’s business. Although we expect that the elimination of duplicative costs, strategic benefits, and additional income, as well as the realization of other efficiencies related to the integration of the business, may offset incremental transaction and Endeavor Acquisition-related costs over time, any net benefit may not be achieved in the near term or at all. If we and Endeavor are not able to adequately address integration challenges, we may be unable to successfully integrate operations or realize the anticipated benefits of the integration of the two companies.
We also expect to incur significant additional indebtedness in connection with the Endeavor Acquisition, which indebtedness may limit our operating or financial flexibility relative to our current position and make it difficult to satisfy our obligations with respect to our other indebtedness.
We will incur debt to finance all or a portion of the cash consideration for the Endeavor Acquisition and to repay certain existing indebtedness of Endeavor. Our increased level of debt in connection with this debt financing could have negative consequences on us and the combined company, including, among other things, (i) requiring us, and the combined company, to dedicate a larger portion of cash flow from operations to servicing and repayment of the debt, (ii) reducing funds available for strategic initiatives and opportunities, working capital and other general corporate needs, (iii) limiting our, and the combined company’s, ability to incur additional indebtedness, which could restrict its flexibility to react to changes in its business, its industry and economic condition and (iv) placing us, and the combined company, at a competitive disadvantage compared to our competitors that have less debt. See also the risks discussed above under “—Risks Related to Our Indebtedness.”
The market value of our common stock could decline if large amounts of our common stock are sold following the Endeavor Acquisition.
If the Endeavor Acquisition is consummated, we will issue 117.27 million shares of our common stock to Endeavor’s equityholders, and as a result, the Endeavor Stockholders are expected to hold, at closing, approximately 39.5% of our outstanding common stock. At closing, we will enter into the Stockholders Agreement with the Endeavor Stockholders that will, among other things, provide the Endeavor Stockholders with certain shelf, demand and piggyback registration
rights. While the Endeavor Stockholders will be subject to a lock-up with respect to 90% of the shares of our common stock issued in the Endeavor Acquisition, the lock-up will apply to 66.6% and 33.3% of the shares issued in the Endeavor Acquisition following the six and twelve month anniversaries, respectively, of the closing and will terminate following the eighteen month anniversary of the closing. Endeavor Stockholders may decide not to hold shares of our common stock that they will receive in the Endeavor Acquisition, and Endeavor Stockholders may decide to reduce their investment in us following the Endeavor Acquisition. Such sales of our common stock or the perception that these sales may occur, could have the effect of depressing the market price for our common stock.
Following the closing of the Endeavor Acquisition, the Endeavor Stockholders will have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders.
As a result of the Endeavor Acquisition, Endeavor’s Stockholders are expected to hold, at closing, approximately 39.5% of our outstanding common stock. The Stockholders Agreement will provide the Endeavor Stockholders with the right to propose for nomination four directors for election to our board of directors if they beneficially own at least 25% of the outstanding shares of our common stock, two directors if they beneficially own at least 20% but less than 25% of the outstanding shares of our common stock, and one director if they beneficially own at least 10% but less than 20% of the outstanding shares of our common stock, in each case subject to certain qualification requirements for such directors. We will not be permitted to take certain actions without the consent of the holders of a majority of the shares of our common stock held by the Endeavor Stockholders. The Endeavor Stockholders level of ownership and influence may make some transactions (such as those involving mergers, material share issuances or changes in control) more difficult or impossible without the support of the Endeavor Stockholders, which in turn could adversely affect the market price of our shares of common stock or prevent our shareholders from realizing a premium over the market price for their shares of our common stock. The interests of the Endeavor Stockholders may conflict with the interests of other stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
Cybersecurity Risk Management Strategy
We have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats. We have engaged third-party consultants to conduct penetration testing and risk assessments. Our cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration.
Our cybersecurity risk management program is integrated into our overall enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas.
Our cybersecurity risk management program includes:
•risk assessments designed to help identify material cybersecurity risks to our critical systems, information, products, services, and our broader enterprise IT environment;
•a security team principally responsible for managing (i) our cybersecurity risk assessment processes, (ii) our security controls, and (iii) our response to cybersecurity incidents;
•the use of external service providers, where appropriate, to assess, test, train or otherwise assist with aspects of our security controls;
•security tools deployed in the IT environment for protection against and monitoring for suspicious activity;
•cybersecurity awareness training of our employees, including incident response personnel and senior management;
•cybersecurity tabletop exercises for members of our cybersecurity incident response team and legal department;
•a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and
•a third-party risk management process for service providers, suppliers, and vendors.
Cybersecurity Governance
Our cybersecurity governance program is led by the Vice President and Chief Information Officer, with support from the internal information technology department. The Vice President and Chief Information Officer has over 20 years of technological leadership experience in the oil and gas industry, providing oversight of all information technology disciplines, including cybersecurity, networking, infrastructure, applications, and data management and protection. The Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), CompTIASecurity+, and Department of Defense (DoD)-Cybersecurity General, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes. In addition, our cybersecurity incident response team is responsible for responding to cybersecurity incidents in accordance with our Computer Security Incident Response Plan. Progress and developments in our cybersecurity governance program are communicated to members of the executive team. The audit committee of the board of directors receives quarterly updates on the status of our cybersecurity governance program, including as related to new or developing initiatives and any security incidents that may occur. Board members receive presentations on cybersecurity topics from the Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies. Further, our code of business conduct and ethics expects all employees to safeguard our electronic communications systems and related technologies from theft, fraud, unauthorized access, alteration or other damage and requires them to report any cyberattacks or incidents, improper access or theft to our Chief Legal and Administrative Officer and the Vice President and Chief Information Officer. Our cybersecurity governance program also includes processes to assess cybersecurity risks related to third-party vendors and suppliers.
Risks from cybersecurity threats have not materially affected, and are not currently anticipated to materially affect, our Company, including our business strategy, results of operations or financial condition. See, however, Item 1A. Risk Factors of this report for additional information regarding cybersecurity risks we face and their potential impact on our business strategy, results of operations and financial condition.
ITEM 3. LEGAL PROCEEDINGS
DueWe are a party to various routine legal proceedings, disputes and claims arising in the natureordinary course of our business, we are,including those that arise from timeinterpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, employment claims, claims alleging violations of antitrust laws, contamination claims relating to time, involved in routine litigation or subjectoil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management,any resulting impact on us, cannot be predicted with certainty, we believe that none of the pending litigation, disputes or claims against us,these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.operations or cash flows. For additional information regarding environmental matters, see Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Price RangeListing and Holders of Common StockRecord
Our common stock is listed on the Nasdaq Global Select Market under the symbol “FANG”.
The following table sets forth the range of high and low sales prices of our common stock for the periods presented:
|
| | | | | | | |
| High | | Low |
2017 | | | |
1st Quarter | $ | 114.00 |
| | $ | 96.05 |
|
2nd Quarter | $ | 108.17 |
| | $ | 83.22 |
|
3rd Quarter | $ | 98.36 |
| | $ | 82.77 |
|
4th Quarter | $ | 127.45 |
| | $ | 95.69 |
|
2016 | | | |
1st Quarter | $ | 79.87 |
| | $ | 55.48 |
|
2nd Quarter | $ | 96.01 |
| | $ | 73.12 |
|
3rd Quarter | $ | 99.69 |
| | $ | 83.90 |
|
4th Quarter | $ | 113.23 |
| | $ | 88.74 |
|
Holders of Record
There were nine5,207 holders of record of our common stock on February 9, 2018.16, 2024.
Dividend Policy
We have not paid any cash
Future base and variable dividends since our inception. Covenants contained in our revolving credit facility restrictare at the payment of cash dividends on our common stock. See Item 1A. “Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Our revolving credit facility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity and Capital Resources–Credit Facility.”
On February 13, 2018, we announced that we are initiating an annual cash dividend in the amount of $0.50 per sharediscretion of our common stock payable quarterly beginning withboard of directors, and the board of directors may change the dividend amount from time to time based on the Company's outlook for commodity prices, liquidity, debt levels, capital resources, free cash flow and other factors. Beginning in the first quarter of 2018. The decision to pay this first dividend or any future dividends, however, is solely within the discretion of, and subject to approval by,2024, our board of directors.directors has approved a reduction in our return of capital commitment to our shareholders to at least 50% from 75% of our quarterly free cash flow through repurchases under our share repurchase program, base dividends and variable dividends. Our board of directors intends to continue the payment of dividends to the holders of the Company’s common stock in the future; however, the Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount or type of any future dividends. Our board of directors’ determination with respect to any such dividends, whether base or variable, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.
Recent Sales of Unregistered Securities
None.
Issuer Repurchases of Equity Securities
None.
Our common stock repurchase activity for the three months ended December 31, 2023 was as follows:
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Period | | Total Number of Shares Purchased(1) | | Average Price Paid Per Share(2)(4) | | Total Number of Shares Purchased as Part of Publicly Announced Plan | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(3)(4) |
| | ($ In millions, except per share amounts, shares in thousands) |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
October 1, 2023 - October 31, 2023 | | 226 | | $ | 147.27 | | | 218 | | $ | 1,731 | |
November 1, 2023 - November 30, 2023 | | 99 | | $ | 149.88 | | | 99 | | $ | 1,716 | |
December 1, 2023 - December 31, 2023 | | 556 | | $ | 148.31 | | | 556 | | $ | 1,634 | |
Total | | 881 | | $ | 148.22 | | | 873 | | |
(1)Includes 8,495 shares of common stock repurchased from executives in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.
(2)The average price paid per share includes any commissions paid to repurchase stock.
(3)On July 28, 2022, our board of directors approved an increase in our common stock repurchase program from $2.0 billion to $4.0 billion, excluding excise tax. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.
(4)The Inflation Reduction Act of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022. All dollar amounts presented exclude such excise taxes, as applicable.
Stock Performance Graph
The following performance graph includes a comparison of our cumulative total stockholder return over a five-year period with the cumulative total returns of the Standard & Poor’s 500 Stock Index, or the S&P 500 Index, and the SPDR S&P Oil & Gas Exploration and Production ETF, or XOP Index. The graph assumes an investment of $100 on December 31, 2018, and that all dividends were reinvested.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, |
Calculated Values | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 |
Diamondback Energy, Inc. | $100.00 | | $100.91 | | $54.49 | | $123.93 | | $167.93 | | $200.88 |
S&P 500 | $100.00 | | $131.47 | | $155.65 | | $200.29 | | $163.98 | | $207.04 |
XOP | $100.00 | | $90.56 | | $57.67 | | $96.18 | | $139.78 | | $144.74 |
ITEM 6. SELECTED FINANCIAL DATA[RESERVED.]
This section presents our selected historical combined consolidated financial data. The selected historical combined consolidated financial data presented below is not intended to replace our historical consolidated financial statements. You should read the following data along with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report on Form 10-K.
Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years ended December 31, 2017, 2016 and 2015 and the balance sheet data as of December 31, 2017 and 2016 are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The historical financial data for the year ended December 31, 2014 and 2013 and the balance sheet data as of December 31, 2015, 2014 and 2013 are derived from our audited financial statements not included in this Annual Report on Form 10-K.
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| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In thousands, except per share amounts) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Statements of Operations Data: | | | | | | | | | |
Total revenues | $ | 1,205,111 |
| | $ | 527,107 |
| | $ | 446,733 |
| | $ | 495,718 |
| | $ | 208,002 |
|
Total costs and expenses | 600,091 |
| | 595,724 |
| | 1,187,002 |
| | 283,048 |
| | 112,808 |
|
Income (loss) from operations | 605,020 |
| | (68,617 | ) | | (740,269 | ) | | 212,670 |
| | 95,194 |
|
Other income (expense) | (107,831 | ) | | (96,099 | ) | | (8,831 | ) | | 92,286 |
| | (8,853 | ) |
Income (loss) before income taxes | 497,189 |
| | (164,716 | ) | | (749,100 | ) | | 304,956 |
| | 86,341 |
|
Provision for (benefit from) income taxes | (19,568 | ) | | 192 |
| | (201,310 | ) | | 108,985 |
| | 31,754 |
|
Net income (loss) | 516,757 |
| | (164,908 | ) | | (547,790 | ) | | 195,971 |
| | 54,587 |
|
Less: Net income attributable to non-controlling interest | 34,496 |
| | 126 |
| | 2,838 |
| | 2,216 |
| | — |
|
Net income (loss) attributable to Diamondback Energy, Inc. | $ | 482,261 |
| | $ | (165,034 | ) | | $ | (550,628 | ) | | $ | 193,755 |
| | $ | 54,587 |
|
Earnings per common share | | | | | | | | | |
Basic | $ | 4.95 |
| | $ | (2.20 | ) | | $ | (8.74 | ) | | $ | 3.67 |
| | $ | 1.30 |
|
Diluted | $ | 4.94 |
| | $ | (2.20 | ) | | $ | (8.74 | ) | | $ | 3.64 |
| | $ | 1.29 |
|
Weighted average common shares outstanding | | | | | | | | | |
Basic | 97,458 |
| | 75,077 |
| | 63,019 |
| | 52,826 |
| | 42,015 |
|
Diluted | 97,688 |
| | 75,077 |
| | 63,019 |
| | 53,297 |
| | 42,255 |
|
|
| | | | | | | | | | | | | | | | | | | |
| As of December 31, |
(In thousands) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Balance Sheet Data: | | | | | | | | | |
Cash and cash equivalents | $ | 112,446 |
| | $ | 1,666,574 |
| | $ | 20,115 |
| | $ | 30,183 |
| | $ | 15,555 |
|
Net property and equipment | 7,343,617 |
| | 3,390,857 |
| | 2,597,625 |
| | 2,791,807 |
| | 1,446,337 |
|
Total assets | 7,770,985 |
| | 5,349,680 |
| | 2,750,719 |
| | 3,095,481 |
| | 1,521,614 |
|
Current liabilities | 577,428 |
| | 209,342 |
| | 141,421 |
| | 266,729 |
| | 121,320 |
|
Long-term debt | 1,477,347 |
| | 1,105,912 |
| | 487,807 |
| | 673,500 |
| | 460,000 |
|
Total stockholders’/ members’ equity(1) | 5,254,860 |
| | 3,697,462 |
| | 1,875,972 |
| | 1,751,011 |
| | 845,541 |
|
Total equity | 5,581,737 |
| | 4,018,292 |
| | 2,108,973 |
| | 1,985,213 |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Other Financial Data: | | | | | | | | | |
Net cash provided by operating activities | $ | 888,625 |
| | $ | 332,080 |
| | $ | 416,501 |
| | $ | 356,389 |
| | $ | 155,777 |
|
Net cash used in investing activities | (3,132,282 | ) | | (1,310,242 | ) | | (895,050 | ) | | (1,481,997 | ) | | (940,140 | ) |
Net cash provided by financing activities | 689,529 |
| | 2,624,621 |
| | 468,481 |
| | 1,140,236 |
| | 773,560 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Consolidated Adjusted EBITDA(2) | $ | 928,039 |
| | $ | 387,535 |
| | $ | 449,245 |
| | $ | 398,334 |
| | $ | 157,604 |
|
| |
(1) | For the years ended December 31, 2017, 2016, 2015 and 2014, total stockholders’ equity excludes $326.9 million, $320.8 million, $233.0 million and $234.2 million, respectively, of non-controlling interest related to Viper Energy Partners LP. There was no equity related to non-controlling interest for the year ended December 31, 2013. |
| |
(2) | Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure. For our definition of Consolidated Adjusted EBITDA and a reconciliation of Consolidated Adjusted EBITDA to net income (loss) see “–Non-GAAP financial measure and reconciliation” below. |
Non-GAAP financial measure and reconciliation
Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external usersTable of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Consolidated Adjusted EBITDA as net income (loss) plus net non-cash (gain) loss on derivative instruments, net interest expense, depreciation, depletion and amortization expense, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, loss on extinguishment of debt, income tax (benefit) provision and non-controlling interest in net (income) loss. Consolidated Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. Management believes Consolidated Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We add the items listed above to net income (loss) in arriving at Consolidated Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Consolidated Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Consolidated Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Consolidated Adjusted EBITDA. Our computations of Consolidated Adjusted EBITDA may not be comparable to other similarly titled measure of other companies or to such measure in our revolving credit facility or any of our other contracts.Contents
The following presents a reconciliation of the non-GAAP financial measure of Consolidated Adjusted EBITDA to the GAAP financial measure of net income (loss).
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| Year Ended December 31, |
(In thousands) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Net income (loss) | $ | 516,757 |
| | $ | (164,908 | ) | | $ | (547,790 | ) | | $ | 195,971 |
| | $ | 54,587 |
|
Non-cash (gain) loss on derivative instruments, net | 84,240 |
| | 26,522 |
| | 112,918 |
| | (117,109 | ) | | (5,346 | ) |
Interest expense, net | 40,554 |
| | 40,684 |
| | 41,510 |
| | 34,515 |
| | 8,059 |
|
Depreciation, depletion and amortization | 326,759 |
| | 178,015 |
| | 217,697 |
| | 170,005 |
| | 66,597 |
|
Impairment of oil and natural gas properties | — |
| | 245,536 |
| | 814,798 |
| | — |
| | — |
|
Non-cash equity-based compensation expense | 34,178 |
| | 33,532 |
| | 24,572 |
| | 14,253 |
| | 2,724 |
|
Capitalized equity-based compensation expense | (8,641 | ) | | (7,079 | ) | | (6,043 | ) | | (4,437 | ) | | (972 | ) |
Asset retirement obligation accretion expense | 1,391 |
| | 1,064 |
| | 833 |
| | 467 |
| | 201 |
|
Loss on extinguishment of debt | — |
| | 33,134 |
| | — |
| | — |
| | — |
|
Income tax (benefit) provision | (19,568 | ) | | 192 |
| | (201,310 | ) | | 108,985 |
| | 31,754 |
|
Non-controlling interest in net (income) loss | (47,631 | ) | | 843 |
| | (7,940 | ) | | (4,316 | ) | | — |
|
Consolidated Adjusted EBITDA | $ | 928,039 |
| | $ | 387,535 |
| | $ | 449,245 |
| | $ | 398,334 |
| | $ | 157,604 |
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. Our activities are primarily directed atAs of December 31, 2023, we have one reportable segment, the horizontal developmentupstream segment. See Note 1—Description of the WolfcampBusiness and Spraberry formationsBasis of Presentation and Note 17—Segment Information in Item 8. Financial Statements and Supplementary Data of this report for further discussion.
2023 Financial and Operating Highlights
•We recorded net income of $3.1 billion.
•Increased our annual base dividend to $3.60 per share of common stock, paid dividends to stockholders of $1.4 billion during 2023 and declared a combined base and variable dividend payable in the first quarter of 2024 of $3.08 per share of common stock.
•Repurchased $838 million of our common stock, leaving approximately $1.6 billion available for future purchases under our common stock repurchase program at December 31, 2023.
•Our cash operating costs were $10.90 per BOE, including lease operating expenses of $5.34 per BOE, cash general and administrative expenses of $0.59 per BOE and production and ad valorem taxes and gathering, processing and transportation expenses of $4.97 per BOE.
•Redeemed or repurchased an aggregate of $140 million in principal amount of our 5.250% Senior Notes due 2023, 3.250% Senior Notes due 2026 and 3.500% Senior Notes due 2029.
•Our average production was 447,707 MBOE/d.
•Drilled 350 gross horizontal wells (including 315 in the Midland Basin and 35 in the WolfcampDelaware Basin).
•Turned 310 gross operated horizontal wells (including 263 in the Midland Basin and Bone Spring formations47 in the Delaware Basin) to production.
•As of December 31, 2023, we had approximately 493,769 net acres, which primarily consisted of 349,707 net acres in the Midland Basin and 143,742 net acres in the Delaware Basin. As of December 31, 2023, we had an estimated 7,905 gross horizontal locations that we believe to be economic at $50.00 per Bbl WTI. In addition, our publicly traded subsidiary, Viper, owns mineral interests underlying approximately 1,197,638 gross acres and 34,217 net royalty acres in the Permian Basin. We intend to continue to develop our reservesoperate approximately 49% of these net royalty acres.
•Incurred capital expenditures, excluding acquisitions, of $2.7 billion.
2023 Transactions and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production.Recent Developments
The following table sets forth our production data for the periods indicated:Acquisitions
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| | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Oil (MBbls) | 74 | % | | 73 | % | | 75 | % |
Natural gas (MMcf) | 12 | % | | 11 | % | | 11 | % |
Natural gas liquids (MBbls) | 14 | % | | 16 | % | | 14 | % |
| 100 | % | | 100 | % | | 100 | % |
On December 31, 2017, our acreage positionNovember 1, 2023, Viper closed on the GRP Acquisition, which included 4,600 net royalty acres in the Permian Basin, wasplus an additional 2,700 net royalty acres in other major basins in exchange for approximately 246,0129.02 million Viper common units and $760 million in cash, including customary closing adjustments.
On September 1, 2023, we contributed the Deep Blue Water Assets with a net carrying value of $692 million in exchange for $516 million in cash, a 30% equity ownership and voting interest in the newly formed Deep Blue joint venture and certain contingent consideration.
On January 31, 2023, we closed on the Lario Acquisition, which included approximately 25,000 gross (206,660 net) acres, which consisted of approximately 117,586 gross (101,941(16,000 net) acres in the Northern Midland Basin and approximately 128,426 gross (104,719 net) acres in the Southern Delaware Basin.
2017 Transactions and Recent Developments
Our Delaware Basin Acquisition
On February 28, 2017, we completed an acquisition ofcertain related oil and natural gas properties, midstream assets and other related assets in the Delaware Basinexchange for an aggregate purchase price consisting of $1.74 billion in cash and 7.694.33 million shares of our common stock and $814 million, including certain customary post-closing adjustments.
Divestitures
On July 28, 2023, we divested our 43% limited liability company interest in OMOG for $225 million in cash received at closing and recorded a gain on the sale of whichequity method investments of approximately 1.15$35 million in the third quarter of 2023 that was included in the caption “Other income (expense), net” on the consolidated statement of operations.
On April 28, 2023, we divested non-core assets with an unrelated third-party buyer consisting of approximately 19,000 net acres in Glasscock County for total consideration of $269 million, including customary post-closing adjustments.
On March 31, 2023, we divested non-core assets consisting of approximately 4,900 net acres in Ward and Winkler counties to unrelated third-party buyers for $72 million in net cash proceeds, including customary post-closing adjustments.
On January 9, 2023, we divested our 10% non-operating equity investment in Gray Oak for $172 million in cash proceeds and recorded a gain on the sale of equity method investments of approximately $53 million in the first quarter of 2023 that was included in “Other income (expense), net” on the consolidated statement of operations.
See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our acquisitions and divestitures.
Recent Developments
On February 11, 2024, we entered into the Merger Agreement to acquire Endeavor for consideration consisting of a base cash amount of $8.0 billion, subject to adjustments under the terms of the Merger Agreement, and approximately 117.27 million shares were placedof our common stock. The Endeavor Acquisition is expected to close in an indemnity escrow. This transaction included the acquisitionfourth quarter of (i)2024, subject to the satisfaction or waiver of customary closing conditions, including the approval of the issuance of our common stock in the Endeavor Acquisition by our stockholders and the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. As a result of the Endeavor Acquisition, the Endeavor Stockholders are expected to hold, at closing, approximately 100,306 gross (80,339 net) acres39.5% of our outstanding common stock.
See Note 16—Subsequent Events in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the Endeavor Acquisition.
Commodity Prices and Inflation
Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. We used the net proceeds from our December 2016 equity offering, net proceeds from our December 2016 debt offering, cash on handfuture, extreme weather conditions and other financing sourcessubstantially variable factors, influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2023, 2022 and 2021 the NYMEX WTI prices averaged $77.60, $94.33 and $68.11 per Bbl, respectively, and the NYMEX Henry Hub prices averaged $2.66, $6.54 and $3.71 per MMBtu, respectively. The war in Ukraine and the Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout 2023. Although the impact of inflation on our business has been insignificant in prior periods, inflation in the U.S. has been rising at its fastest rate in over 40 years, creating inflationary pressure on the cost of services, equipment and other goods in the energy industry and other sectors, which is contributing to labor and materials shortages across the supply-chain. Additionally, OPEC and its non-OPEC allies, known collectively as OPEC+, continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels.
Outlook
During 2023, we had total capital expenditures of $2.7 billion, which was consistent with our guidance presented in November 2023. In 2024, we expect to maintain flat production throughout the year with less capital and activity than 2023, thereby promoting our commitment to capital efficiency. Beginning in the first quarter of 2024, our board of directors approved a reduction to our return of capital commitment to our shareholders to at least 50% from 75% of our quarterly free cash flow (as defined in “—Capital Requirements”). Because we will add debt to fund the cash portion of the purchase price for this acquisition.Endeavor Acquisition, we are going to allocate more free cash flow to pay down our debt, with a near-term goal to get pro forma net debt below $10 billion through free cash flow generation and potential non-core asset sales. Our long-term priority is to
New Senior Notes
On January 29, 2018, we issued $300.0 million aggregate principal amount of new 2025 notes as additional notes under our existing indenture, dated as of December 20, 2016, as supplemented, among us, subsidiary guarantors party thereto and Wells Fargo, as trustee, under which we previously issued $500.0 million aggregate principal amount of our existing 5.375% Senior Notes due 2025. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.
Viper Equity Offerings
In January 2017, Viper completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuantreturn cash to an optionstockholders, and we believe using free cash flow to purchase additional common units granted topay down newly-added debt is in the underwriters. Viper received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.
In July 2017, Viper completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, we purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directorsbest long-term interest of our Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, we had an approximate 64% limited partner interest in Viper. Viper received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $152.8 million to repay all of the then-outstanding borrowings under Viper’s revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes.stockholders.
Operational Update
We are operating ten rigs now and currently intend to operate between ten and twelve drilling rigs in 2018 across our asset base in the Midland and Delaware Basins. We plan to operate six to seven of these rigs in the Midland Basin targeting horizontal development of the Wolfcamp and Spraberry formations, with four to five rigs are expected to operate in the Delaware Basin targeting the Wolfcamp and Bone Spring formations.
In the Midland Basin, we continuecontinued to have positive results across our core development areas located within Midland, Martin, Howard, Glasscock and Andrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations. We are currently operating six rigs on the acreage and expect to average approximately six to eight operated rigs in 2018.
In the Delaware Basin, we have now drilledcontinued to target the Wolfcamp and completed multiple wellsBone Spring formations across our primary development areas located in Pecos, Reeves and Ward counties targetingcounties. Collectively, the Wolfcamp A, whichDelaware Basin accounted for approximately 15% of our total development in 2023, and we believe has been de-risked acrossexpect a significantsimilar portion of our total development to be focused in these areas in 2024.
As of December 31, 2023, we were operating 15 drilling rigs and four completion crews and currently intend to operate between 12 and 15 drilling rigs and between three and four completion crews in 2024 on average across our current acreage position and remains our primary development target. Additionally, we have successfully completed additional wells targeting such zones as the Wolfcamp B and 2nd Bone Spring, and expect to test these zones further in 2018. We are currently operating four rigs in the Midland and Delaware Basin and plan to average approximately four to five rigs in 2018.Basins.
We continue to focus on low cost operations and best in class execution. In doing so, we are focused on controlling oilfield service costs as our service providers seek to increase pricing following continued strength in the oil market. To combat rising service costs, we have looked to lock in pricing for dedicated activity levels and will continue to seek opportunities to control additional well cost where possible. Our 2018 drilling and completion budget accounts for rising capital costs that we believe will cover potential increases in our service costs during the year.
2018 Capital Budget
We have currently budgeted a 20182024 total capital spend of $1.3$2.30 billion to $1.5$2.55 billion, consistingwhich at the midpoint is a reduction of $1.175 billion10% year over year due to $1.325 billion for horizontal drillinga combination of lower well costs and completions including non-operatedlower activity and $125.0 million to $175.0 million for infrastructure and other expenditures, but excluding the cost of any leasehold and mineral interest acquisitions.expected in 2024. We expect to drill approximately 275 wells and complete 170turn approximately 310 wells to 190production, with almost 30% of those wells expected to be turned to production in the first quarter of 2024. Should commodity prices weaken, we intend to act responsibly and, consistent with our prior practices, reduce capital spending. If commodity prices strengthen, we intend to maintain flat oil production, pay down indebtedness and return cash to our stockholders.
Environmental Responsibility Initiatives and Highlights
In September 2022, we announced our medium-term goal to reduce Scope 1 and Scope 2 greenhouse gas (“GHG”) intensity by at least 50% from our 2020 level by 2030. In May 2022, we announced our short-term goal to implement continuous emission monitoring systems (“CEMS”) on our facilities to cover at least 90% of operated oil production by the end of 2023. As of December 31, 2023, we had installed CEMS that cover approximately 96% of our operated oil production.
In September 2021, we announced our near-term goal to end routine flaring (as defined by the World Bank) by 2025 and a near-term target to source over 65% of our water used for drilling and completion operations from recycled sources by 2025. For the full year ended 2023, we flared approximately 3.4% of our gross horizontal wellsnatural gas production and sourced approximately 73% of our water used for drilling and completion operations from recycled sources.
In February 2021, we announced significant enhancements to our commitment to environmental, social responsibility and governance, or ESG, performance and disclosure, including Scope 1 and methane emission intensity reduction targets. Our goals include the reduction of our Scope 1 greenhouse gas intensity by at least 50% and methane intensity by at least 70%, in 2018.each case by 2024 from the 2019 levels. To further underscore our commitment to carbon neutrality, we have also implemented our “Net Zero Now” initiative under which, effective January 1, 2021, we strive to produce every hydrocarbon molecule with zero net Scope 1 emissions. To the extent our greenhouse gas and methane intensity targets do not eliminate our carbon footprint, we have purchased carbon credits to offset the remaining emissions. ESG metrics represent 25% of our annual short-term incentive compensation plan to motivate our executives and our employees to advance our environmental responsibility goals.
Operating Results Overview
The following table summarizes our average daily production for the periods presented:
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| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Oil (Bbls)/d | 58,678 | | 31,590 | | 24,880 |
Natural Gas (Mcf)/d | 56,602 | | 29,313 | | 21,729 |
Natural Gas Liquids (Bbls)/d | 11,112 | | 6,556 | | 4,596 |
Total average production per day | 79,224 | | 43,031 | | 33,098 |
2024 Guidance
Our average daily production for the year ended December 31, 2017 as compared to the year ended December 31, 2016 increased by 36,193 BOE/d, or 84%.
During the year ended December 31, 2017, we drilled 150 gross (130 net) horizontal wells and participated in the drilling of 16 gross (two net) non-operated horizontal wells in the Permian Basin.
Reserves and pricing
Ryder Scott prepared estimates of our proved reserves at December 31, 2017, 2016 and 2015 (which include estimated proved reserves attributable to Viper). The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
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| 2017 | | 2016 | | 2015 |
Estimated Net Proved Reserves: | | | | | |
Oil (MBbls) | 233,181 |
| | 139,174 |
| | 105,979 |
|
Natural gas (MMcf) | 285,369 |
| | 174,896 |
| | 149,503 |
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Natural gas liquids (MBbls) | 54,610 |
| | 37,134 |
| | 26,004 |
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Total (MBOE) | 335,352 |
| | 205,458 |
| | 156,899 |
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| Unweighted Arithmetic Average |
| First-Day-of-the-Month Prices |
| 2017 | | 2016 | | 2015 |
Oil (per Bbl) | $ | 48.03 |
| | $ | 39.94 |
| | $ | 45.07 |
|
Natural gas (per Mcf) | $ | 2.06 |
| | $ | 1.36 |
| | $ | 1.83 |
|
Natural gas liquids (per Bbl) | $ | 20.79 |
| | $ | 12.91 |
| | $ | 12.56 |
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Sources of our revenue
Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices.
The following table presents the sourcesour current estimates of our revenuescertain financial and operating results for the years presented:full year of 2024, as well as production and cash tax guidance for the first quarter of 2024:
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| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Revenues | | | | | |
Oil sales | 88 | % | | 89 | % | | 91 | % |
Natural gas sales | 4 | % | | 4 | % | | 4 | % |
Natural gas liquid sales | 8 | % | | 7 | % | | 5 | % |
| 100 | % | | 100 | % | | 100 | % |
| | | | | |
| 2024 Guidance |
Net production - MBOE/d | 458 - 466 |
Oil production - MBO/d | 270 - 275 |
Q1 2024 oil production - MBO/d (total - MBOE/d) | 270 - 274 (458 - 464) |
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(Unit costs $/BOE): | |
Lease operating expenses, including workovers | $6.00 - $6.50 |
General and administrative expenses - cash | $0.55 - $0.65 |
Non-cash stock-based compensation | $0.40 - $0.50 |
Depreciation, depletion, amortization and accretion | $10.50 - $11.50 |
Interest expense (net of interest income) | $1.05 - $1.25 |
Gathering, processing and transportation | $1.80 - $2.00 |
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Production and ad valorem taxes (% of revenue) | ~7% |
Corporate tax rate (% of pre-tax income) | 23% |
Cash tax rate (% of pre-tax income) | 15% - 18% |
Q1 2024 cash taxes (in millions) | $150 - $190 |
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Since our production consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas liquids or natural gas prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2017, WTI posted prices ranged from $42.48 to $60.46 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On December 29, 2017, the WTI posted price for crude oil was $60.46 per Bbl and the Henry Hub spot market price of natural gas was $3.69 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.