As filed with the U.S. Securities and Exchange Commission on September 13, 2024.
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Peak Resources LP
(Exact name of registrant as specified in its charter)
| Delaware | 1311 | 99-2937133 | ||
(State or other jurisdiction of incorporation or organization) | (Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification No.) |
1910 Main Avenue
Durango, Colorado 81301
(970) 247-1500
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Jack E. Vaughn
Chief Executive Officer
1910 Main Avenue
Durango, Colorado 81301
(970) 247-1500
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
Jesse E. Betts Jessica W. Hammons Akin Gump Strauss Hauer & Feld LLP 2300 N. Field Street Suite 1800 Dallas, Texas 75201 (214) 969-2800 | Clinton H. Smith Victoria J. Bagot Jones Walker LLP 201 St. Charles Avenue Suite 5100 New Orleans, Louisiana 70170 (504) 582-8000 |
Approximate date of commencement of proposed sale of the securities to the public:
As soon as practicable after the effective date of this Registration Statement.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: ☐
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☐ | Accelerated filer | ☐ | |||
| Non-accelerated filer | ☒ | Smaller reporting company | ☒ | |||
| Emerging Growth Company | ☒ | |||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐
The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
The information in this prospectus is not complete and may be changed. We may not sell the securities described herein until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell the securities described herein and it is not soliciting an offer to buy such securities in any jurisdiction where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED , 2024
PRELIMINARY PROSPECTUS
Class A Common Units
Peak Resources LP is a Delaware limited partnership focused on the development and production of oil and natural gas reserves in the Powder River Basin of Wyoming. This is the initial public offering of Class A Common Units of Peak Resources LP. We are offering Class A Common Units, each Class A Common Unit representing a limited partner interest in the Company. No public market currently exists for any of the Class A Common Units. We expect the initial public offering price to be between $ and $ per Class A Common Unit. We intend to apply to list the Class A Common Units on the NYSE American (the “NYSE American”) under the symbol “PRB.” We will not consummate this offering unless our Class A Common Units are approved for listing on the NYSE American. We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act.
Investing in our securities involves risks. See “Risk Factors” beginning on page 34 of this prospectus.
These risks include the following:
| • | Cash distributions may fluctuate with our performance, and we may not have sufficient cash available to pay any quarterly distribution on our Class A Common Units. |
| • | Oil and natural gas prices are volatile. A substantial or extended decrease in prices of these commodities could adversely affect our business, financial condition, results of operations, ability to meet our financial commitments, ability to make our planned capital expenditures and distributions. |
| • | Unless we replace the reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations, results of operations and our ability to make distributions. |
| • | We must adhere to stringent requirements by multiple governing agencies—all of which have the potential to adversely impact the cost and feasibility of our endeavors, and/or expose us to significant risk of liability. |
| • | Our general partner and its affiliates own a controlling interest in us and may have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders. |
| • | Our unitholders have limited voting rights and are not entitled to elect our general partner or the Board, which could reduce the price at which our Class A Common Units will trade. |
| • | Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent (other than for cause). |
| • | We are treated as a corporation for U.S. federal income tax purposes, and distributions to our Class A Common Unitholders may be substantially reduced. |
PRICE $ PER CLASS A COMMON UNIT
| Per Class A Common Unit | Total | |||||||
Public offering price | $ | $ | ||||||
Underwriting discount(1) | $ | $ | ||||||
Proceeds, before expenses | $ | $ | ||||||
| (1) | Includes an aggregate structuring fee equal to % of the gross proceeds of this offering payable to Janney Montgomery Scott LLC. Please read “Underwriting.” |
We have granted the underwriters a 30-day option to purchase up to an additional Class A Common Units on the same terms and conditions as set forth above if the underwriters sell more than Class A Common Units in this offering.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The underwriters expect to deliver the Class A Common Units on or about , 2024.
Lead Book-Running Manager
Janney Montgomery Scott
Joint Book-Running Managers
Roth Capital Partners | Texas Capital Securities |
Co-Manager
Seaport Global
, 2024
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Employment Contracts, Termination of Employment, Change-in-Control Arrangements | 174 | |||
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT | 176 | |||
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Distributions and Payments to Our General Partner and Its Affiliates | 179 | |||
Agreements with Affiliates in Connection with the Reorganization Transactions | 180 | |||
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APPENDIX A AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF PEAK RESOURCES LP | A-1 | |||
| B-1 |
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We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We are not, and the underwriters are not, making an offer to sell the securities described herein in any jurisdiction where an offer or sale is not permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Class A Common Units. Our business, financial condition, results of operations and prospects may have changed since that date.
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” in this prospectus.
Through and including , 2024 (the 25th day after the date of this prospectus), all dealers effecting transactions in our securities, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.
The market data and certain other statistical information included in this prospectus are based on a variety of sources, including independent industry publications, government publications and other published independent sources. Some data is also based on our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” in this prospectus.
We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.
Unless otherwise indicated, the historical financial information presented in this prospectus represents the financial statement combination of certain entities under common control, namely Peak Exploration & Production, LLC, a Delaware limited liability company (“Peak E&P”), and Peak BLM Lease LLC, a Delaware limited liability company (“PBLM”). The combined financial statements of Peak E&P and PBLM are referred to
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as the predecessor for accounting purposes. The pro forma financial information also includes certain information related to a minority ownership position in PetroSantander, Inc., a Canadian corporation (“PSI”), and is included herein as indicated.
This prospectus contains unaudited pro forma financial information, which presents certain financial information and operating data of our predecessor and PSI on a pro forma combined basis, as adjusted to give effect to the initial public offering and the use of proceeds therefrom and the Reorganization Transactions (as defined herein) as if they had occurred at the beginning of the periods presented. The production, reserve, acreage, well count, drilling locations, and other historical data in this prospectus are presented on a pro forma combined basis as if the Reorganization Transactions had occurred unless otherwise indicated.
The entities to be contributed in connection with the initial public offering and the Reorganization Transactions described in this prospectus have a high degree of common ownership and therefore the Reorganization Transactions are accounted for as common control transactions. Peak E&P and PBLM have been in operation and under common control for the entirety of the periods presented. Affiliates of Yorktown Partners LLC (“Yorktown”) will control the general partner, which will ultimately control business operations. Accordingly, the financial statements are presented in accordance with SEC requirements for predecessor financial statements to be included in the registration statement.
Unless another date or source is specified, all production, operational, acreage, well count and drilling location data presented in this prospectus is as of June 30, 2024. Unless another date or source is specified, all reserve data presented in this prospectus is as of December 31, 2023. Our reserves and production are reported in two streams: crude oil and natural gas. The economic value of the natural gas liquids is included in the natural gas price and in our natural gas reserves.
The terms “dollar” or “$” refer to U.S. dollars. Unless otherwise specified, all dollar amounts are expressed in U.S. dollars.
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This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully before making an investment decision, including the information under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the notes thereto appearing elsewhere in this prospectus. The information presented in this prospectus assumes (i) an initial public offering price of $ per Class A Common Unit (the midpoint of the price range set forth on the cover of this prospectus) and (ii) unless otherwise indicated, that the underwriters do not exercise their option to purchase an additional Class A Common Units in this offering.
Except as otherwise indicated or required by the context, all references in this prospectus to “our general partner” refer to Peak Resources GP LLC, a Delaware limited liability company, and all references in this prospectus to the “Company,” the “Partnership,” “Peak Resources LP,” “we,” “us” or “our” refer to (i) prior to the Reorganization Transactions described in this prospectus, to Peak Exploration & Production, LLC and its consolidated subsidiaries (“Peak E&P”), Peak BLM Lease LLC and its consolidated subsidiaries (“PBLM”) and a minority ownership position in PetroSantander, Inc. (“PSI”) and (ii) following the Reorganization Transactions described in this prospectus, to Peak Resources LP and its consolidated subsidiaries. We have provided definitions for certain of the industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” included in this prospectus as Appendix B. References to our proved reserves as of December 31, 2023 are derived from our reserve report prepared by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), our independent petroleum engineers, and references to our proved reserves as of December 31, 2022 are derived from the summation of the reports prepared by Cawley Gillespie for Peak E&P and PBLM. Immediately prior to the closing of this offering, we intend to complete the Reorganization Transactions described in this prospectus pursuant to which the Company will acquire certain assets, including (i) 100% of the ownership interests in Peak E&P, (ii) 100% of the ownership interests in PBLM and (iii) an approximately 16% minority ownership position in PSI. We account for our noncontrolling ownership interest in PSI using the cost method of accounting. The carrying value of the Partnership’s investment in PSI on the balance sheet included in our consolidated financial statements is at cost.
We are an independent limited partnership that was recently formed to hold investments in oil and natural gas businesses and assets owned by certain investment partnerships managed by Yorktown, management and other investors who are not affiliated with Yorktown or management. Our objective is to consistently create significant equity value for the holders of our Class A Common Units (each, a “Class A Common Unitholder” and collectively, the “Class A Common Unitholders”) in two ways: first, to actively develop and expand our large acreage position in the Powder River Basin of Wyoming in a way that materially increases oil and associated natural gas production, cash flow, and reserve value; and second, to return cash to Class A Common Unitholders through a quarterly distribution of Available Cash (as defined below).
Our primary operational focus is on using advanced horizontal drilling and completion technology to economically and expeditiously grow our oil and natural gas production and reserves in the Powder River Basin, which we believe remains less developed from a horizontal drilling perspective than most other basins in the United States. We are focused on increasing equity value through the development of our 1,770 gross (530 net) identified horizontal drilling locations. We seek to organically grow our production profile through the low-risk development of our existing properties, funded by cash flow from operating activities and a portion of the net proceeds of this offering. We also believe that the Powder River Basin offers opportunities to make future accretive acquisitions of producing properties and acreage. We expect such acquisitions, together with our development activities, will allow us to further increase our production, reserves and free cash flow, and over time, increase distributions to our unitholders.
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We are offering Class A Common Units in this offering. The Class A Common Units will entitle Class A Common Unitholders to quarterly distributions of Available Cash. Our partnership agreement requires us to distribute all of our Available Cash. We define “Available Cash” as our cash on hand at the end of each quarter, plus certain distributions or dividends received after the end of the quarter, plus certain working capital borrowings and proceeds from this offering if determined by our general partner, less cash reserves established by our general partner, including for the proper conduct of our business, such as for capital expenditures, acquisitions, debt service, compliance with law and loan agreements and future distributions. We intend to make quarterly distributions of Available Cash on our Class A Common Units. Our goal is to make a distribution of at least $ per Class A Common Unit per quarter (adjusted for the number of days in the first quarterly period after the closing date of this offering), which we refer to as our initial target quarterly distribution. However, to the extent there is no Available Cash, our partnership agreement does not require us to pay distributions on our Class A Common Units on a quarterly basis or otherwise.
Our goal is to make consistent quarterly distributions to our Class A Common Unitholders at or above our initial target quarterly distribution that grow over time, based on the attractive economics associated with our development locations and our large multi-year inventory of operated locations. Additionally, we believe our balance sheet strength following this offering, our accretive acquisition opportunities and our expected supplemental dividends from PSI will help us grow our distributions over time. However, we have no legal obligation to pay cash distributions to our Class A Common Unitholders, and there is no guarantee that we will make quarterly cash distributions to our Class A Common Unitholders at the initial target quarterly distribution amount, or at all, or that distributions will grow over time. The amount of cash flow from operations available for distribution with respect to any quarter will be dependent on the then-prevailing prices of oil and natural gas, among other factors. To mitigate the risk associated with volatile commodity prices and to satisfy the requirement under our Existing Credit Agreement (as hereinafter defined), we will hedge, on a rolling quarterly basis, a portion of our production volumes based on reasonably anticipated projected production of proved developed producing reserves that we are required to hedge. To the extent our Distributable Cash from Operations (as hereinafter defined) is insufficient to pay our quarterly distributions, we may use cash on hand, including proceeds from this offering initially designated as reserves, to maintain or grow our cash distributions to our Class A Common Unitholders. See “The Offering—Non-GAAP Financial Measures—Distributable Cash from Operations” for our definition of Distributable Cash from Operations. For example, on a pro forma basis, if we had completed the transactions contemplated in this prospectus on January 1, 2023, our pro forma Distributable Cash from Operations would have been approximately $15.4 million for the year ended December 31, 2023 and $14.5 million for the twelve months ended June 30, 2024, which would have been sufficient to pay our initial target quarterly distributions for the quarters in those periods. Additionally, our forecasted Distributable Cash from Operations for the twelve months ending June 30, 2025 is expected to be approximately $8.3 million, which would be sufficient to pay our initial target quarterly distributions for the quarters in that period. However, our forecasted Distributable Cash from Operations for the twelve months ending December 31, 2025 would be insufficient to pay our initial target quarterly distributions for the quarters in that period, so all or a portion of the quarterly cash distributions to our Class A Common Unitholders would need to be made from our cash on hand, including from proceeds from this offering initially designated as reserves.
The Company is structured in a manner where our general partner will hold a small number of Class A Common Units and a general partner interest that will not entitle it to receive cash distributions until such time as the Company has grown its quarterly cash distribution to the Class A Common Unitholders above the initial target quarterly distribution per Class A Common Unit, after which time our general partner will receive an amount equal to 10% of the amount distributed above the initial target quarterly distribution per Class A Common Unit. The general partner will not be entitled to its 10% share of any such amount for the first six full calendar quarters after the closing of this offering. Management will hold Class B Common Units that will not be listed on any stock exchange and will not pay a cash distribution, other than distributions of Available Cash from capital surplus, distributions of proceeds from the sale of our investment in PSI and any liquidating distributions. However, the
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Class B Common Units will be mandatorily convertible into Class A Common Units based upon an excess Distributable Cash from Operations coverage test, which we intend will protect the existing Class A Common Unitholder distribution. See “The Offering—Non-GAAP Financial Measures—Distributable Cash from Operations” for our definition of Distributable Cash from Operations. The mandatory conversion is subject to review and election of our general partner. As a result, our general partner and management have a strong incentive to grow Available Cash that will accrue to the benefit of the investors in this offering. See “Description of Our Securities—Conversion of Class B Common Units.”
In addition, pursuant to the Reorganization Transactions described in this prospectus, certain investment partnerships managed by Yorktown and other non-Yorktown affiliated investors will receive Class B Common Units in exchange for their common and preferred ownership interests in Peak E&P, PBLM and PSI. These Class B Common Units will not be listed on any stock exchange and will not pay a cash distribution, other than distributions of Available Cash from capital surplus, distributions of proceeds from the sale of our investment in PSI and any liquidating distributions. However, these Class B Common Units will be mandatorily convertible (at the election of our general partner) into Class A Common Units based upon an excess Distributable Cash from Operations coverage test, which we intend will protect the existing Class A Common Unitholder distribution. See “Description of Our Securities—Conversion of Class B Common Units.”
Experienced Management Team
Peak E&P was formed by our management team and investment partnerships managed by Yorktown in 2011 to identify, evaluate, acquire and develop onshore oil and natural gas assets in the United States. Peak E&P is led by Jack E. Vaughn, Glen E. Christiansen and Justin M. Vaughn, who have over 90 years of collective experience operating in the exploration and production industry.
PBLM was formed by an investment partnership managed by Yorktown in 2017 to identify and fund the acquisition of additional high-quality acreage in the Powder River Basin for development by Peak E&P.
Our management team has an established track record of identifying, developing and efficiently operating oil and natural gas assets in the Powder River Basin as well as other premier onshore U.S. basins. Moreover, members of our management team were key participants in the early implementation of advanced drilling techniques in the Granite Wash (Anadarko Basin) as well as the shift from vertical to horizontal drilling and the application of advanced completion techniques in the Barnett Shale (Fort Worth Basin) and Bakken Shale (Williston Basin). In total, our Chief Executive Officer and Yorktown have worked together to navigate three prior successful upstream exits, with an average return on investment of 296%, excluding general and administrative and other expenses. We believe our management team’s experience provides us with a competitive advantage in the identification of opportunities in the Powder River Basin and continues to drive our top-tier operational performance; however, the prior performance of companies or business initiatives in which our management team or Yorktown were involved may not be indicative of our future performance.
Upon completion of this offering, our management team will consist of Jack E. Vaughn, Chief Executive Officer; Ali A. Kouros, Executive Vice President, Corporate Development and Strategy; Glen E. Christiansen, President and Chief Operating Officer; and Justin M. Vaughn, Executive Vice President and Chief Financial Officer. Our management team will be supported by employees, including geologists, completion and drilling engineers, land personnel, regulatory and environmental specialists, as well as field operating personnel.
Powder River Basin, Wyoming, USA
Our primary operational focus is on using advanced horizontal drilling and completion technology to economically and expeditiously grow our oil and natural gas production and proved reserves in the Powder River Basin. We believe that the geologic characteristics and in-place resources of the Powder River Basin make it one
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of the most attractive regions in the United States for the development and production of oil and associated natural gas. The Powder River Basin consists of an expansive and thick gross column with multiple, proven productive horizons that are conducive to the application of horizontal drilling and completion techniques using state-of-the-art technology. We believe this results in high oil and natural gas recoveries and attractive economic returns relative to drilling and completion costs, lower drilling risk, high initial production rates and long reserve life. Further, we believe at this current development stage, the Powder River Basin remains less developed from a horizontal drilling perspective, which presents many years of attractive development opportunities.
Utilizing their experience in identifying unconventional resource development opportunities, our management team analyzed the geologic potential of numerous North American basins and decided to make the Powder River Basin our focal point. The Powder River Basin has a long history of oil and natural gas development through the vertical development of its extensive oil reservoirs, and later through the development of its coal bed methane reserves. Like the Permian Basin, the Powder River Basin has been substantially delineated through the drilling of more than 33,000 vertical oil and natural gas wells. However, in our opinion, unlike the Permian Basin, the Powder River Basin’s tight oil resource has yet to be widely re-developed with advanced horizontal drilling and completion technologies.
We believe the reservoir quality and stacked pay potential of the Powder River Basin is similar to that of the Permian Basin, with an approximate 4,000-foot gross column, high oil content and significant over-pressure, with multiple productive horizons as deep as 13,500 feet. In addition, the geographic location of the Powder River Basin provides us with attractive realized pricing and operating leverage due to its proximity to end markets, installed infrastructure with ample capacity for growth, access to in-basin service providers and what we view as a favorable regulatory climate in the State of Wyoming for hydrocarbon development operations.
As of June 30, 2024, we had approximately 65,000 gross (45,000 net) acres comprised of private, state, and federal lands with a number of large, contiguous leasehold blocks in the over-pressured core of the Powder River Basin, primarily in Campbell and Converse Counties, Wyoming. We have drilled and operate a total of 104 gross (56 net) producing horizontal wells. In addition, we have drilled two gross (one net) horizontal wells awaiting completion. We also own interests in an additional 83 gross (five net) non-operated, producing horizontal wells with an average working interest of approximately 6.0%. All 83 gross (five net) non-operated wells are operated primarily by other leading Powder River Basin operators including EOG Resources, Devon Energy, Anschutz Exploration, and Ballard Petroleum. Our small working interest in these non-operated wells allows us the benefit of ascertaining other operators’ techniques and advances at a relatively small cost. The following map illustrates our acreage positions within the Powder River Basin, consisting primarily of leased acreage in Campbell County, Wyoming, with additional positions in Johnson County and Converse County, Wyoming.
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We have identified 1,770 gross (530 net) horizontal drilling locations across our acreage in the Powder River Basin, the majority of which target the Parkman, Shannon, Turner, Niobrara and Mowry reservoirs. We believe that
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a significant portion of our inventory in the Turner and Shannon horizons (over-pressured, marine-influenced, tight sandstone formations) and the Parkman horizon (normally pressured, marine-influenced, tight sandstone formation) has been substantially delineated by the number of horizontal and vertical wells drilled on or within the vicinity of our acreage and has lowered the geologic and operational risk. Furthermore, we have been actively developing the Mowry and Niobrara horizons, which are both organic-rich, over-pressured, tight shale formations. Combining our results with those of other offset operators, attractive returns in these horizons have been proven at current commodity prices utilizing advanced drilling and completion techniques and technology. We also see additional potential development opportunities in the Teapot, Sussex, Muddy and Dakota formations. Based on our near-term development program, and assuming that we drill an average of eight gross wells per year, we have a multi-decade drilling inventory. We have identified 1,770 gross (530 net) horizontal drilling locations within our approximately 65,000 gross (45,000 net) acre position, of which at a 10% internal rate of return, 658 gross (244 net) locations are currently economic at $55.00 per barrel for oil and $1.85 per MMBtu for natural gas, and 1,198 gross (423 net) locations are economic at $70.00 per barrel for oil and $2.36 per MMBtu for natural gas. Furthermore, if we increase our current development cadence from eight gross wells per year to 24 gross wells per year (i.e., one full-time rig per year), our inventory would still span 27 years using the 658 gross (244 net) locations from the lower pricing assumptions above. As of December 31, 2023, our total estimated proved oil and natural gas reserves were approximately 16,247 Mboe, based on our annual reserve report prepared by Cawley Gillespie. Because our reserves are reported in two streams, the economic value of the NGLs is included in our natural gas price and natural gas reserves. Our proved reserves are comprised of approximately 59% oil and 41% natural gas and are approximately 50% proved developed.
The following table sets forth a summary, as of December 31, 2023, of our gross and net identified horizontal drilling locations by reservoir.
| Identified Horizontal Drilling Locations(1)(2)(3)(4) | ||||||||
| Gross | Net | |||||||
Parkman | 162 | 61 | ||||||
Shannon | 82 | 29 | ||||||
Turner | 259 | 87 | ||||||
Niobrara | 712 | 196 | ||||||
Mowry | 526 | 147 | ||||||
Teapot | 12 | 3 | ||||||
Sussex | 17 | 7 | ||||||
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Total | 1,770 | 530 | ||||||
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| (1) | The above table includes 1,074 gross (354 net) of our identified horizontal drilling locations that have been evaluated by Cawley Gillespie, our independent reserve engineer, along with 696 gross (176 net) identified horizontal drilling locations that have not been evaluated by Cawley Gillespie that were based solely on the internal evaluations of our management. See “Risk Factors—Risks Related to Our Business—A portion of our identified horizontal drilling locations are based on our management’s internal estimates and were not based on evaluations prepared by Cawley Gillespie.” |
| (2) | Identified horizontal drilling locations represent total gross and net locations that have either been evaluated by Cawley Gillespie or specifically identified by management as an estimate of our future multi-year drilling inventory on existing acreage. We have estimated our drilling locations based upon our interpretation of available geologic and engineering data as well as the evaluation of the performance of vertical and horizontal wells drilled on and within the vicinity of our acreage. Our actual drilling activities may change depending on oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add additional reserves to our existing reserves. Further, to the extent the drilling locations are associated with acreage that expires, we would lose |
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| our right to develop the related locations. See “Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry—Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.” |
| (3) | Our identified horizontal drilling location count assumes the following with respect to wells per drilling and spacing unit (“DSU”) and spacing for each of our targeted reservoirs: |
| Gross Wells per DSU | Spacing (in feet) | |||||||
Parkman | 4 | 1,056 | ||||||
Shannon | 2 | 1,760 | ||||||
Turner | 3 | 1,320 | ||||||
Niobrara* | 4 | 1,056 | ||||||
Mowry | 4 | 1,056 | ||||||
Teapot | 3 | 1,320 | ||||||
Sussex | 2 | 1,760 | ||||||
| * | Niobrara locations generally assume four wells per DSU. However, in the eastern portion of Campbell County, the Niobrara develops two distinct reservoirs and as a result, a total of eight gross wells per DSU have been identified (four wells in the Upper Niobrara and four wells in the Lower Niobrara). |
| (4) | One-mile laterals represent horizontal wells expected to be drilled on a 640-acre DSU. Typically, these horizontal wells are drilled with a lateral length of approximately 4,000 feet. Two-mile laterals represent horizontal wells that are drilled across a 1,280-acre DSU. Typically, these horizontal wells are drilled with a lateral length of approximately 9,500 feet. While a portion of our locations represent one-mile laterals, we anticipate there will be increasing opportunities to shift many of these locations towards the drilling and completion of horizontal wells with two-mile laterals. |
International Assets
Although our operational focus is on developing our large acreage holdings in the Powder River Basin, in connection with the Reorganization Transactions and immediately prior to the closing of this offering, we will acquire a non-controlling, approximately 16% minority equity position in PSI, a private, Canadian company formed in 1995 and headquartered in Houston, Texas. PSI owns international oil and natural gas assets, primarily in Colombia and Brazil.
PSI operates oil and natural gas fields in Colombia, most of which are located in the Middle Magdalena Valley Basin (Las Monas Block). PSI also operates five oil and gas fields in Romania, with approximately 660 Boe/d, but is planning on a full exit of the country by December 2024. During the year ended December 31, 2023, PSI’s average operated daily net production in Colombia was approximately 2,370 Boe/d with 132 active wells, and PSI’s revenue with respect to its non-RECV (as defined below) operations was approximately $54.4 million.
PSI also owns an indirect interest in Brazilian operations through its approximately 20% ownership of PetroReconcavo S.A. (“RECV”), a publicly-held company that trades on the Sao Paulo Stock Exchange under the ticker symbol RECV3:SAO. As of the close of business on June 30, 2024, RECV’s market capitalization was approximately $979 million. RECV has primarily grown through the acquisition of conventional and mature onshore oil and natural gas properties in Brazil and the subsequent development of those properties. For the year ended December 31, 2023, RECV reported average daily production of approximately 26,000 Boe/d, 835 active wells, revenues of approximately $560 million, and $58 million in dividends paid to its shareholders. We account for our non-controlling ownership interest in PSI using the cost method of accounting. The carrying value of the Partnership’s investment in PSI on the balance sheet included in our consolidated financial statements is at cost.
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We will acquire our interest in PSI from two investment partnerships managed by Yorktown in the Reorganization Transactions described below. Historically, PSI has paid significant dividends to its shareholders, and we expect PSI to continue to pay dividends in the future, although it has no obligation to do so and we have no influence or control over PSI’s payment of dividends. We plan to use any future dividends we receive from PSI to fund capital expenditures, to pay cash distributions and for other general uses. For the years ended December 31, 2021, 2022 and 2023, PSI paid aggregate dividends with respect to the approximately 16% minority interest we will acquire in the Reorganization Transaction of $22.1 million, an average of approximately $7.3 million per year.
Development Plan and Capital Budget
Historically, our business plan has focused on acquiring and then developing non-producing acreage. Funding sources for our activities have included cash from our partners, proceeds from borrowings, and cash flow from operating activities.
We spent approximately $10.6 million on development costs for the year ended December 31, 2023. Our capital budget for the year ending December 31, 2024 is approximately $7.1 million (of which $4.1 million has been paid as of June 30, 2024). Based on current commodity prices and our drilling success rate to date, we expect to fund our 2024 capital development program from cash flow from operating activities and proceeds from this offering. For the twelve months ending December 31, 2025, we intend to use cash flow from operating activities and a portion of our proceeds for this offering to significantly increase capital expenditures to approximately $69.8 million. Our development efforts and capital for the year ending December 31, 2024 are primarily focused on the completion of one gross drilled but uncompleted horizontal well, along with commencing the drilling of two gross (one net) horizontal wells, which are expected to be completed in early 2025. For the years ending December 31, 2025, 2026 and 2027, we anticipate a continued focus on the drilling and completion of additional wells, with 13 gross (11 net) wells expected to be drilled and 10 gross (eight net) wells expected to be completed in 2025, 11 gross (eight net) wells expected to be drilled and 13 gross (11 net) wells expected to be completed in 2026, and six gross (five net) wells expected to be drilled and nine gross (seven net) wells expected to be completed in 2027. The objective of these activities is to consistently grow net production over the next several years.
By operating a high percentage of our acreage, we are better able to control the cadence of our development activities and the corresponding amount and timing of our capital expenditures. We may choose to defer a portion of these planned capital expenditures or modify our rig count depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated commodity prices, the availability of necessary equipment, infrastructure, drilling rigs, labor and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions and drilling and completion costs. Additionally, our projected capital budget includes our expectations regarding the amount of capital that will be required for non-operated development activity. The amount of capital that may ultimately be spent on non-operated development activity may vary based on the development activities of the applicable operators. Any reduction in our capital expenditure budget could delay or limit our development program, which could materially and adversely affect our ability to grow production and our future business, financial condition, results of operations and liquidity. Our development plan and capital budget are based on management’s current expectations and assumptions about future events. While we consider these expectations and assumptions to be reasonable, they are subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. For further discussion of the risks we face, see “Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry.”
Our primary business objective is to consistently create significant equity value for our Class A Common Unitholders through a combination of (i) growing our production, cash flow and reserve value and (ii) returning
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cash to our Class A Common Unitholders through stable and growing cash distributions. To achieve our objective, we intend to execute the following business strategies:
Grow cash flows, reserves and production by developing our extensive oil-focused resource base in the Powder River Basin. We have built an extensive oil-focused inventory of 1,770 gross (530 net) identified horizontal drilling locations predominately targeting our five main producing horizons in the Powder River Basin. We also see additional potential development opportunities in the Teapot, Sussex, Muddy and Dakota formations. We believe our extensive inventory of oil-focused drilling locations, together with our long-lived reserves and operating expertise, will enable us to create equity value by growing cash flow, reserves and production in the current commodity price environment. We intend to utilize these increased cash flows to make quarterly cash distributions to our Class A Common Unitholders, fund future capital programs and grow our acreage position.
Strategically grow our acreage position through opportunistic bolt-on acquisitions and leasing opportunities while increasing our working interest in existing acreage. Our management team has a demonstrated track record of identifying and executing on attractive resource development opportunities. Since entering the Powder River Basin in 2012, we have consummated nearly 78 opportunistic bolt-on acquisitions and acreage purchases in the Powder River Basin, acquiring approximately 45,000 net acres as of December 31, 2023. We intend to build upon these successes and pursue similar opportunistic bolt-on and strategic acquisitions in the Powder River Basin. We also expect to continue to use the Wyoming “forced pooling” process to increase our working interest in wells we propose to drill as operator, which could lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well.
Focus on making cash distributions to, and providing long-term value for, our Class A Common Unitholders. Our primary goal is to maximize investor returns through cash distributions and attractive growth of our production and oil and gas reserve value. Our goal is to make a distribution of at least $ per Class A Common Unit per quarter (adjusted for the number of days in the first quarterly period after the closing date of this offering), which we refer to as our initial target quarterly distribution. Although our partnership agreement requires that we distribute all of our Available Cash, if any, quarterly, we have no legal obligation to do so, and there is no guarantee that we will make quarterly cash distributions to our Class A Common Unitholders at the initial target quarterly distribution amount, or at all, or that distributions will grow over time. However, we intend to grow production annually and acquire acreage over time, while continuing to provide consistent quarterly distributions to our Class A Common Unitholders at or above our initial target quarterly distribution, with a goal of increasing the long-term value of our Class A Common Units.
Maintain financial flexibility with a conservative capital structure and a strong liquidity profile. We intend to conduct our operations primarily through cash flow generated from operations with a focus on maintaining a strong balance sheet with significant cash reserves and little to no net debt. We intend to initially keep our existing debt facility in place, but we are currently negotiating a New Credit Facility (as defined below) with prospective lenders. If we enter into a New Credit Facility after the closing of this offering, we will use borrowings under the New Credit Facility and a portion of the proceeds from this offering to repay in full and terminate our Existing Credit Agreement (as defined below). See “Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction—Expected Refinancing Transactions” for additional information. Due to our strong operating cash flows and post-offering liquidity, we expect to have substantial flexibility to fund our capital budget and to potentially accelerate our drilling program as conditions warrant. Our focus is on the economic extraction of hydrocarbons while maintaining a prudent leverage ratio and strong liquidity profile. Although we may use leverage to make accretive acquisitions, we expect to do so with the long-term goal of maintaining a strong balance sheet. To mitigate the risk associated with volatile commodity prices and to satisfy the requirement under our Existing Credit Agreement (as hereinafter defined), we will hedge a portion of our production volumes, on a rolling quarterly basis, based on reasonably anticipated projected production of proved developed producing reserves that we are required to hedge.
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Leverage our geologic and operational expertise to enhance operating efficiencies and maximize returns. We believe our management and technical teams are among the best operators in the Powder River Basin. We regularly benchmark our operating data against our own historical results as well as those of other Powder River Basin operators in order to evaluate our performance, identify opportunities to improve our drilling and completion techniques and make informed decisions about our capital program and drilling activity levels. Our team is focused on utilizing our geologic expertise to analyze the geological characteristics of the horizons we intend to develop, which allows us to develop techniques specifically tailored to each horizon.
Improve returns through the use of advanced drilling and completion techniques, technology and increasing lateral lengths. We continuously seek efficiencies in our drilling, completion and production techniques to optimize ultimate resource recoveries, rates of return and cash flows. Since inception, we have strived to be on the leading-edge of deploying advanced completion technology in the Powder River Basin. We intend to continue to leverage our management and technical teams’ geologic and operational experience in applying unconventional drilling and completion techniques in the Powder River Basin to maximize our returns and will allocate capital towards next generation technologies where applicable.
We believe that the following strengths will allow us to successfully execute our business strategies:
Our sole basin focus promotes optimized development of our concentrated position in the oil and liquids-rich Powder River Basin. While we have exposure to international production through our non-controlling position in PSI, our primary and sole operating focus is on the development of our Powder River Basin assets. Additionally, while the majority of the top operators in the Powder River Basin are large, diversified companies with operations in multiple basins, our operations are focused exclusively in the Powder River Basin. As of December 31, 2023, we were the fifth largest private pure Powder River Basin operator based on gross equivalent production, and the tenth largest producer overall in the Powder River Basin. Our single basin focus has allowed us to develop expertise in the Powder River Basin and to work on refining area-specific drilling and completion designs. Upon completion of this offering, we will be the only public company solely operating in the Powder River Basin, and we intend to leverage our deep knowledge of the basin, along with our understanding of the geology and reservoir properties of potential acquisition targets, to identify and opportunistically acquire prospective bolt-on acreage that improves our potential drilling outcomes and meets our strategic and financial objectives.
Highly experienced management team with a track record of creating value. Our management team has an established track record operating in the Powder River Basin and other premier onshore U.S. basins and is experienced in the identification, evaluation, execution and integration of acquisitions. Members of our management team have a long history of working together on the cost-efficient management of leading-edge development programs, including three in the Granite Wash (Anadarko Basin), the Barnett Shale (Fort Worth Basin) and the Bakken Shale (Williston Basin). Our Chief Executive Officer and Yorktown have led activities in other active plays and basins, growing a cumulative investment of approximately $340 million to approximately $1 billion over the course of three successful upstream exit transactions, with an average return on investment of 296%, excluding general and administrative and other expenses. We believe our management team is able to leverage their experience to create equity value through organic development of our existing assets and opportunistic acquisitions; however, the prior performance of companies or business initiatives in which our management team or Yorktown were involved may not be indicative of our future performance.
Low-risk acreage position with multi-year inventory of oil-weighted drilling locations. We have a large inventory of drilling opportunities in the core of the Powder River Basin. As of December 31, 2023, our horizontal drilling inventory evaluated by Cawley Gillespie consisted of 1,074 gross (354 net) locations, primarily targeting the Parkman, Shannon, Turner, Niobrara and Mowry horizons. Between September 1, 2024
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and December 31, 2026, we expect to drill 26 gross (20 net) operated wells and complete 23 gross (19 net) operated wells. Based on our near-term development program, assuming we drill an average of eight gross wells per year, we have a multi-decade opportunity set. We have identified 1,770 gross (530 net) horizontal drilling locations within our approximately 65,000 gross (45,000 net) acre position, of which at a 10% internal rate of return, 658 gross (244 net) locations are currently economic at $55.00 per barrel for oil and $1.85 per MMBtu for natural gas, and 1,198 gross (423 net) locations are economic at $70.00 per barrel for oil and $2.36 per MMBtu for natural gas. Furthermore, if we increase our current development cadence from eight gross wells per year to 24 gross wells per year (i.e., one full-time rig per year), our inventory would still span 27 years using the 658 gross (244 net) locations from the lower pricing assumptions above. Our production stream is oil weighted, and we envision increasing our average oil production from 55-60% to approximately 60-70% of our total equivalent production over the next three years.
Balanced asset portfolio with significant capital allocation flexibility. Our acreage spans all hydrocarbon mix windows of the Powder River Basin, giving us the flexibility to adjust our capital plan and drilling program to rebalance our production as the commodity price environment evolves. Because approximately 70% of our net acreage position was held by production as of December 31, 2023, and we have the ability to extend many of our material, non-producing leases beyond 2026 for approximately $2.5 million and potentially renew the remaining non-producing leases beyond 2026 for an additional $1.4 million, we are able to opportunistically allocate our human and capital resources to focus on certain windows to produce the commodity mix that is expected to provide the highest potential rate of return at that given time.
Positioned in the Powder River Basin with existing infrastructure built to gather and transport higher volumes than are currently being produced in the basin results in a present-day underutilization. The first oil well in the Powder River Basin was drilled in 1889. Since that time, the Powder River Basin has experienced multiple waves of conventional development. Starting in 2012, horizontal development began and production growth followed. As of December 2023, the Powder River Basin was producing nearly 181 MBbls/d – roughly four times the production from the low in 2009. The Powder River Basin has available refining and takeaway capacity of 1,097 MBbls/d, significantly above current production. Our average net daily production for the year ended December 31, 2023 was approximately 2,947 Boe/d, from approximately 60 net wells. As a result of the legacy production along with the recent upswing in activity, we believe the oil infrastructure in place across our acreage has sufficient capacity to support our anticipated production growth.
Geographically advantaged assets with regional price advantages. Our acreage position is in close proximity to end markets for our oil and natural gas, which provides us with a regional price advantage. For example, in 2023, we sold all of our operated oil production to purchasers in the Powder River Basin, which was then refined in Casper, Rawlins or Newcastle, Wyoming, which are all approximately 75 miles from our acreage position. We expect to continue to sell a majority of our operated oil production on a go-forward basis at attractive prices with all-in differentials of approximately ($3.00) per barrel against the NYMEX WTI. Our operated natural gas also realizes competitive pricing. For example, in 2023, we sold all of our operated natural gas production for $0.02/Mcf over NYMEX Henry Hub, including all transportation, compression and enhancement fees and percentage of proceeds paid to the gas gatherers and marketers. We expect to continue to sell a majority of our operated natural gas production on a go-forward basis at attractive prices that are at or near NYMEX Henry Hub pricing.
Strong relationships with local landowners and government authorities. We have purposefully developed strong relationships with surface and mineral interest owners in the Powder River Basin, which we believe provides us with a competitive advantage in acquiring additional leasehold and operatorship positions. Furthermore, our management’s substantial experience in the Powder River Basin and extensive interactions with the relevant state and federal regulatory bodies allow us to efficiently and effectively navigate the regulatory process, which affords us opportunities to assume operatorship and expand our ownership.
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Significant operational control allowing us to improve drilling results and economic returns. As operator, we are able to control the timing and design of our development program. We believe this affords us the flexibility to efficiently develop our acreage by adjusting drilling, completion and production activities opportunistically to react to changes in the operational and economic environment, such as changes in commodity prices, service costs and access to services.
Exposure to international operations and supplemental cash dividends. Through our approximately 16% non-controlling investment in PSI, we anticipate receiving future cash dividends. For the years ended December 31, 2021, 2022 and 2023, PSI paid aggregate dividends with respect to the approximately 16% minority interest we will acquire in the Reorganization Transaction of $22.1 million, an average of $7.3 million per year. We believe that our ownership position in PSI will continue to provide us with cash dividends to supplement our operational cash flow; however, we are not solely relying on these dividends in our financial planning and budgeting.
An investment in our Class A Common Units involves risks associated with our cash distributions, our business, our partnership structure and the tax consequences of owning the Class A Common Units, among other things. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before investing in our Class A Common Units. Some of the most significant challenges and risks we face include the following:
Risks Related to Cash Distributions on our Class A Common Units
| • | Cash distributions may fluctuate with our performance, and we may not have sufficient cash available to pay any quarterly distribution on our Class A Common Units. |
| • | The assumptions underlying the forecast of Available Cash for distribution to our Class A Common Unitholders we include in “Our Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results. |
| • | The amount of our quarterly cash distributions from Available Cash, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution and could pay no distribution with respect to any particular quarter. |
| • | Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to Class A Common Unitholders. |
Risks Related to Our Business and the Oil and Natural Gas Industry
| • | Oil and natural gas prices are volatile. A substantial or extended decrease in prices of these commodities could adversely affect our business, financial condition, results of operations, ability to meet our financial commitments, ability to make our planned capital expenditures and distributions. |
| • | Unless we replace the reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations, results of operations and our ability to make distributions. |
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| • | If commodity prices decline and remain depressed for a prolonged period, production from a significant portion of our properties may become uneconomic and cause downward adjustments of our reserve estimates and write downs of the value of such properties, which may adversely affect our financial condition and our ability to make distributions. |
| • | Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. |
| • | A portion of our identified horizontal drilling locations are based on our management’s internal estimates and were not based on evaluations prepared by Cawley Gillespie. |
| • | Our development projects and potential future acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves. |
| • | Our U.S. producing properties are concentrated in the Powder River Basin, making us vulnerable to risks associated with operating in a single geographic area. |
| • | The unavailability, high cost or shortages of drilling rigs, fracking crews, equipment, raw materials, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis. |
| • | Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition, results of operations and cash distributions. |
| • | Declining general economic, business or industry conditions, including high inflation, may have a material adverse effect on our results of operations, liquidity and financial condition. |
| • | Events outside of our control, including an epidemic or outbreak of an infectious disease or the threat thereof, could have a material adverse effect on our business, liquidity, financial condition, results of operations, cash flows and ability to pay distributions. |
| • | We use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk. |
| • | Reserve estimates depend on many interpretations and assumptions. Any significant inaccuracies in reserve estimates or underlying interpretations or assumptions will materially affect the quantities and present value of our reserves. |
| • | Our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application. |
| • | Our Existing Credit Agreement contains restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions. |
| • | Increased attention to ESG matters and conservation measures may adversely impact our business. |
| • | Prolonged negative investor sentiment toward upstream natural gas and oil-focused companies could limit our access to capital funding, which would constrain liquidity. |
Risks Related to Environmental and Regulatory Matters
| • | We must adhere to stringent requirements by multiple governing agencies—all of which have the potential to adversely impact the cost and feasibility of our endeavors, and/or expose us to significant risk of liability. |
| • | Our operations are subject to a series of risks arising from the threat of climate change, which could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for the oil and natural gas we produce. |
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Risks Inherent in an Investment in Us
| • | Our general partner and its affiliates own a controlling interest in us and may have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders. |
| • | The conversion of Class B Common Units into Class A Common Units could lead to selling pressure on the Class A Common Unit price. |
| • | Our partnership agreement does not restrict our Sponsors and their respective affiliates from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities. |
| • | Our partnership agreement requires that we distribute all of our Available Cash, if any, which could limit our ability to grow our reserves and production and make acquisitions. |
| • | Our partnership agreement replaces our general partner’s fiduciary duties to our unitholders with contractual standards governing its duties, and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. |
| • | Our unitholders have limited voting rights and are not entitled to elect our general partner or the Board, which could reduce the price at which our Class A Common Units will trade. |
| • | Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent (other than for cause). |
| • | Control of our general partner may be transferred to a third party without unitholder consent. |
| • | We may issue an unlimited number of additional units, including units that are senior to the Class A Common Units, without unitholder approval, which may dilute your ownership interest in us. |
| • | Once our Class A Common Units are publicly traded, the Existing Owners may sell their Class A Common Units in the public markets, which sales could have an adverse impact on the trading price of the Class A Common Units. |
| • | Our general partner has a limited call right that may require you to sell your Class A Common Units and at an undesirable time or price. |
| • | For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation. |
Tax Risks to Purchasers of Class A Common Units in this Offering
| • | We are treated as a corporation for U.S. federal income tax purposes, and our distributions to our Class A Common Unitholders may be substantially reduced. |
| • | Distributions to Class A Common Unitholders may be taxable as dividends. |
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Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction
Reorganization Transactions and Partnership Structure
As part of our reorganization, immediately prior to the closing of this offering:
| • | 100% of the common units in Peak E&P, including the common units held by Yorktown Energy Partners IX, L.P. (“Yorktown IX”) and the members of our management team, will be contributed to the Company in exchange for Class B Common Units; |
| • | 100% of the preferred units in Peak E&P, including the preferred units held by Yorktown Energy Partners X, L.P. (“Yorktown X”), and Yorktown Energy Partners XI, L.P. (“Yorktown XI”), will be contributed to the Company in exchange for Class B Common Units; |
| • | 100% of the ownership interests in PBLM, all of which is held by Yorktown XI, will be contributed to the Company in exchange for Class B Common Units; and |
| • | an aggregate of approximately 16% of the equity in PSI, held by Yorktown Energy Partners VIII, L.P. (“Yorktown VIII”) and Yorktown IX, will be contributed to the Company in exchange for Class A Common Units and Class B Common Units, respectively (all recipients of units in the Reorganization Transactions (as defined below) are referred to herein as the “Existing Owners”). |
We will amend and restate our partnership agreement to reflect the reorganization as outlined above (collectively, the “Reorganization Transactions”).
Expected Refinancing Transaction
As of June 30, 2024, Peak E&P had $57.35 million of outstanding borrowings under the Fortress-Peak Credit and Guaranty Agreement (the “Existing Credit Agreement”). We may elect to use a portion of the net proceeds of this offering to repay a portion of the Existing Credit Agreement, which would include payment of the applicable prepayment fee. Please see “Use of Proceeds” for additional information.
We are in the process of negotiating a new credit facility (the “New Credit Facility”) at the Partnership level with prospective lenders that we anticipate entering into after the completion of this offering. The amount, maturity, interest rates and other terms of the New Credit Facility are in the process of being negotiated with prospective lenders; however, we expect that the aggregate commitments thereunder will be approximately $150.0 million with an initial borrowing base of $45.0 million. The New Credit Facility will be secured by substantially all of our assets, and we expect the covenants in the New Credit Facility will be more favorable than under the terms of the Existing Credit Agreement. For a description of the covenants under the Existing Credit Agreement, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements—Existing Credit Agreement.” Borrowings under the New Credit Facility may vary significantly from time to time depending on our cash needs at any given time.
If we enter into the New Credit Facility after the closing of this offering, we will use borrowings under the New Credit Facility and a portion of the net proceeds of this offering to repay in full (including payment of the applicable prepayment fee) and terminate Peak E&P’s Existing Credit Agreement. However, we have not yet obtained binding commitments for the New Credit Facility. If we are unable to obtain binding commitments for the New Credit Facility on acceptable terms, or at all, the Existing Credit Agreement may remain outstanding after this offering. We cannot assure you that we will obtain binding commitments for the New Credit Facility. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements,” “Risk Factors” and “Use of Proceeds.”
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Ownership and Organizational Structure of Peak Resources LP
The diagram below depicts our organization and ownership before giving effect to the offering and the Reorganization Transactions.
The diagram below depicts our organization and ownership after giving effect to this offering and the Reorganization Transactions and assumes that the underwriters do not exercise their option to purchase additional Class A Common Units.
| (1) | Yorktown VIII, Yorktown IX, Yorktown X, and Yorktown XI are investment partnerships managed by Yorktown. |
| (2) | Immediately upon the consummation of the Reorganization Transactions, Yorktown VIII, Yorktown IX, Yorktown X, and Yorktown XI will collectively beneficially own approximately % of our outstanding Class A Common Units on an as-converted basis because of the ownership of Class B Common Units by Yorktown IX, Yorktown X and Yorktown XI. |
| (3) | Immediately upon the consummation of the Reorganization Transactions, Yorktown IX, Yorktown X and Yorktown XI will collectively own approximately % of the outstanding Class B Common Units. |
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| (4) | Our general partner has one class of member interests, all of which are owned by members of our executive management team, members of our Board, some of whom are also affiliated with Yorktown, and other individuals affiliated with Yorktown. Such owners of our general partner are referred to as the “Sponsors.” |
| (5) | Immediately upon consummation of this offering, our general partner will continue to be owned by the Sponsors, who collectively with Yorktown, will own and control the voting of an aggregate of approximately % of our outstanding Class A Common Units and Class B Common Units, voting as a single class. |
Management of Peak Resources LP
We are managed and operated by the board of directors (the “Board”) and executive officers of our general partner. Our unitholders will not be entitled to elect our general partner or its directors or otherwise participate in our management or operations. Additionally, our general partner may not be removed except for cause by a vote of the holders of at least 66 2/3% of the outstanding Class A Common Units and Class B Common Units, including any Class A Common Units and Class B Common Units owned by our general partner, its members and their respective affiliates, voting together as a single class and we receive an opinion of counsel regarding limited liability matters. For information about the executive officers and directors of our general partner, please read “Management.”
Our general partner has one class of member interests, all of which are owned by members of our executive management team, members of the Board, some of whom are also affiliated with Yorktown, and other individuals affiliated with Yorktown (collectively, the “Sponsors”).
Yorktown VIII, Yorktown IX, Yorktown X, and Yorktown XI, which are investment partnerships managed by Yorktown, will beneficially own approximately % of our outstanding Class A Common Units immediately after this offering (or % of our outstanding Class A Common Units on an as-converted basis as a result of their ownership of Class B Common Units). Immediately upon the consummation of the Reorganization Transactions, the funds affiliated with Yorktown will own approximately % of the outstanding Class B Common Units. Yorktown is an energy-focused private equity firm with a 33-year track record targeting control-oriented investments in free cashflow-focused assets in partnership with best-in-class management teams. Over three decades, Yorktown has invested more than $8 billion in targeted energy sectors and has an investment team with diverse experience across the entire energy sector. We believe our relationship with Yorktown gives us access to a highly accomplished and aligned investment partner.
Implications of Being an Emerging Growth Company
We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”). For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:
| • | provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002; |
| • | provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations, nor more than two years of selected financial data in a registration statement on Form S-1; |
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| • | comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; or |
| • | provide certain disclosure regarding executive compensation required of larger public companies required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). |
In addition, Section 107 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies. As a result, we will not be subject to new or revised accounting standards at the same time as other public companies that are not emerging growth companies. We intend to take advantage of the other exemptions discussed above, both in this prospectus and in future filings with the U.S. Securities and Exchange Commission (the “SEC”). Accordingly, the information contained herein and that we provide to our unitholders from time to time may be different than the information you receive from other public companies. For additional information, see “Risk Factors—Risks Inherent in an Investment in Us—For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation” and “Risk Factors—Risks Inherent in an Investment in Us—Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our Class A Common Units less attractive to investors.”
We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have equal to or more than $1.235 billion in annual revenue, (iii) the date on which we issue more than $1 billion of non-convertible debt over a three-year period or (iv) the date on which we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
Principal Executive Offices and Internet Address
Our principal executive office is located at 1910 Main Avenue, Durango, Colorado 81301, and our telephone number at that address is (970) 247-1500. We also maintain an office in Denver, Colorado. Following the closing of this offering, our website will be located at www. .com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”) available, free of charge, through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.
Summary of Conflicts of Interest and Duties
Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is not adverse to our best interests. However, because our general partner is wholly owned by the Sponsors, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner
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that is beneficial to the Sponsors. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including the Sponsors, on the other hand. For example, our general partner is entitled to make determinations that affect our ability to generate the cash flow necessary to make cash distributions to our unitholders, including determinations related to:
| • | purchases and sales of oil and natural gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that may also be suitable for the Sponsors or any affiliate of the Sponsors; |
| • | the manner in which our business is operated; |
| • | the level of our borrowings; |
| • | the amount, nature and timing of our capital expenditures; and |
| • | the amount of cash reserves necessary or appropriate to satisfy our general, administrative and other expenses and debt service requirements and to otherwise provide for the proper conduct of our business. |
For a more detailed description of the conflicts of interest and duties of our general partner, please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”
Our partnership agreement can generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding Class A Common Units and Class B Common Units, including any such Class A Common Units and Class B Common Units owned by our general partner, its members and their respective affiliates, voting together as a single class. Immediately upon consummation of this offering, our general partner will continue to be owned by the Sponsors, who collectively with Yorktown, will own and control the voting of an aggregate of approximately % of our outstanding Class A Common Units and Class B Common Units, voting as a single class. Assuming that we do not issue any additional voting units and Yorktown does not transfer its Class A Common Units or Class B Common Units, Yorktown will have the ability to amend our partnership agreement, including our policy to distribute all of our Available Cash to our Class A Common Unitholders, without the approval of any other unitholders. Please see “Risk Factors—Risks Inherent in an Investment in Us” and “The Partnership Agreement—Amendment of the Partnership Agreement.”
Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the Partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including our Sponsor and its affiliates, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a Class A Common Unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each such holder consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties — Duties of Our General Partner” for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our Class A Common Units. For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”
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Issuer | Peak Resources LP |
Securities offered by us | Class A Common Units, each Class A Common Unit representing a limited partner interest in the Company ( Class A Common Units if the underwriters exercise in full their option to purchase additional Class A Common Units). |
Number of securities to be outstanding | See chart below. |
| Before this offering(1) | After this offering(2) | |||||||
Class A Common Units | ||||||||
Class B Common Units(3) | ||||||||
| (1) | Includes the consummation of the Reorganization Transactions and the issuance of Class A Common Units and Class B Common Units to the Existing Owners contemplated thereby immediately prior to this offering. |
| (2) | Assumes the underwriters have not exercised their over-allotment option. |
| (3) | Class B Common Units are mandatorily convertible (at the election of our general partner) on a one-for-one basis into Class A Common Units, subject to certain conversion metrics being satisfied. See “Description of Our Securities—Conversion of Class B Common Units.” |
Use of proceeds | We expect the net proceeds from this offering to be approximately $ million ($ million if the underwriters exercise their option in full to purchase additional Class A Common Units), based upon the assumed initial public offering price of $ per Class A Common Unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and estimated expenses and the structuring fee. We expect that $ million of the net proceeds will be used to fund capital expenditures by the Company’s subsidiaries and that approximately $ of the net proceeds will be used to pay bonuses to certain of our executives related to the consummation of this offering. We expect that $ million of the net proceeds will remain at the Partnership initially designated as a reserve for general partnership purposes, including in order to pay distributions on our Class A Common Units if needed. |
We are currently negotiating the New Credit Facility with prospective lenders, and if we enter into the New Credit Facility after the closing of this offering, we will use borrowings under the New Credit Facility and a portion of the net proceeds of this offering to repay in full (including payment of the applicable prepayment fee) and terminate our Existing Credit Agreement. We cannot assure you that we will obtain binding commitments for the New Credit Facility. If we are unable to obtain binding commitments for the New Credit Facility on acceptable terms, or at all, the Existing Credit Agreement may remain outstanding after this offering. See “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected
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Refinancing Transaction—Expected Refinancing Transactions” for additional information.
Cash distributions to Class A Common Unitholders | Under our current cash distribution policy, within 90 days after the end of each quarter, beginning with the quarter ending , 2024, we intend to make quarterly distributions of Available Cash to the holders of our Class A Common Units. Available Cash will include cash on hand at the end of such quarter, plus certain distributions or dividends received after the end of the quarter, plus certain working capital borrowings and proceeds from this offering if determined by our general partner, less cash reserves established by our general partner, including for the proper conduct of our business, such as for capital expenditures, acquisitions, debt service, compliance with law and loan agreements and future distributions. |
| Our ability to pay such cash distributions is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” We will prorate the amount of our distribution payable for the period from the closing of this offering through , 2024, based on the actual length of that period. |
| Our partnership agreement generally provides that we will distribute all of our Available Cash each quarter. Our goal is to make a distribution of at least $ per Class A Common Unit per quarter (adjusted for the number of days in the first quarterly period after the closing date of this offering), which we refer to as our initial target quarterly distribution. Our general partner will receive 10% of the amount distributed above the initial target quarterly distribution per Class A Common Unit after the sixth full calendar quarter following the consummation of this offering (and also share in distributions from capital surplus, liquidating distributions and distributions of proceeds from any sale of our investment in PSI). However, to the extent there is no Available Cash, we have no legal obligation to pay cash distributions to our Class A Common Unitholders, and there is no guarantee that we will make quarterly cash distributions to our Class A Common Unitholders at the initial target quarterly distribution amount, or at all, or that distributions will grow over time. |
If we had completed the transactions contemplated in this prospectus on January 1, 2023, our pro forma Distributable Cash from Operations would have been approximately $15.4 million for the year ended December 31, 2023 and $14.5 million for the twelve months ended June 30, 2024, which would have been sufficient to pay our initial target quarterly distributions for the quarters in those periods. Additionally, our forecasted Distributable Cash from Operations for the twelve months ending June 30, 2025 is expected to be approximately $8.3 million, which would be sufficient to pay our initial target quarterly distributions for the quarters in that period. However, our forecasted Distributable Cash from Operations for the twelve months |
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ending December 31, 2025 would be insufficient to pay our initial target quarterly distributions for the quarters in that period, so all or a portion of the quarterly cash distributions to our Class A Common Unitholders would need to be made from our cash on hand, including from proceeds from this offering initially designated as reserves. Our historical and pro forma financial statements do not include the estimated incremental expenses of being a publicly traded company. However, our forecast of Distributable Cash from Operations for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025 includes the estimated incremental expenses of being a publicly-traded company. For a calculation of our ability to pay distributions to our unitholders based on our pro forma results for the year ended December 31, 2023, and the twelve months ended June 30, 2024, and based on our forecasted results for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025, please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Distributable Cash from Operations for the Year Ended December 31, 2023 and the Twelve Months Ended June 30, 2024” and “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Distributable Cash from Operations for the Twelve Months Ending June 30, 2025 and the Twelve Months Ending December 31, 2025.” |
| We believe, based on our financial forecast and the related assumptions included under “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Distributable Cash from Operations for the Twelve Months Ending June 30, 2025 and the Twelve Months Ending December 31, 2025,” that we will have sufficient Available Cash to make cash distributions at our initial target quarterly distribution of $ per Class A Common Unit on all Class A Common Units (on an annualized basis) for the four quarter period ending June 30, 2025 and the quarters in the period ending December 31, 2025. We cannot guarantee that we will make any particular amount of distributions or any distributions to our unitholders in any quarter. Please read “Our Cash Distribution Policy and Restrictions on Distributions.” |
Issuance of additional units | We can issue an unlimited number of additional units, including units that are senior to the Class A Common Units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Class A Common Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Partnership Interests.” |
Limited voting rights | Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our Class A Common Unitholders will have only limited voting rights on matters affecting our business. Our Class A Common Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. Our general partner may not be removed unless that removal is |
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for cause and is approved by the vote of the holders of not less than 66 2/3% of the outstanding Class A Common Units and Class B Common Units, including any Class A Common Units and Class B Common Units owned by our general partner, its members and their respective affiliates, voting together as a single class, and we receive an opinion of counsel regarding limited liability matters. Immediately upon consummation of this offering, our Sponsors and Yorktown will own an aggregate of approximately % of our Class A Common Units and Class B Common Units, which would vote together as a single class, and, therefore, will be able to prevent the removal of our general partner. Please read “The Partnership Agreement—Limited Voting Rights.” |
Limited call right | If at any time our general partner and its affiliates own more than 80% of the actual, outstanding Class A Common Units, our general partner has the right, but not the obligation, to purchase all of the remaining Class A Common Units at a purchase price not less than the then-current market price of the Class A Common Units, as calculated pursuant to the terms of our partnership agreement. Immediately upon consummation of this offering, affiliates of Yorktown (including our Sponsors) will own an aggregate of approximately % of our outstanding Class A Common Units (or % of our outstanding Class A Common Units on an as-converted basis as a result of their ownership of Class B Common Units). Please read “The Partnership Agreement—Limited Call Right.” |
Election to be treated as a corporation | The Partnership has made an election to be treated as an entity taxable as a corporation for U.S. federal income tax purposes effective as of its formation date. |
Eligible Holders and redemption | Class A Common Units held by persons who our general partner determines are not Eligible Holders will be subject to redemption. As used herein, an “Eligible Holder” means any person or entity qualified to hold an interest in oil and natural gas leases on U.S. federal lands. |
| We have the right (which we may assign to any of our affiliates), but not the obligation, to redeem all of the Class A Common Units of any holder that is not an Eligible Holder or that has failed to certify or has falsely certified that such holder is an Eligible Holder. The purchase price for such redemption would be equal to the then-current market price of the Class A Common Units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of Our Securities—Transfer of Class A Common Units” and “The Partnership Agreement—Non-Citizen Unitholders; Redemption.” |
Material tax consequences | For a discussion of material federal income tax consequences that may be relevant to prospective unitholders, please read “Material U.S. Federal Income Tax Consequences.” |
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Listing and trading symbol(s) | We intend to apply for the listing of our Class A Common Units on the NYSE American under the symbol “PRB.” We will not consummate this offering unless our Class A Common Units are approved for listing on the NYSE American. |
Summary Predecessor Combined Historical and Pro Forma Financial and Operating Data
The summary predecessor combined historical consolidated financial data set forth below as of and for each of the years ended December 31, 2023 and 2022 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The summary predecessor combined historical consolidated financial data set forth below as of June 30, 2024 and for the six months ended June 30, 2024 and 2023 are derived from our unaudited condensed consolidated financial statements included elsewhere in this prospectus.
The summary unaudited pro forma financial data as of June 30, 2024 and for the six months ended June 30, 2024 and for the year ended December 31, 2023 are derived from the unaudited pro forma condensed financial statements of Peak Resources LP included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:
| • | the Reorganization Transactions as described in “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction” elsewhere in this prospectus summary; and |
| • | the issuance and sale by us to the public of Class A Common Units in this offering and the application of the net proceeds of the offering as described in “Use of Proceeds.” |
The summary unaudited pro forma financial data were prepared as if the items listed above occurred on January 1, 2023, in the case of statement of operations data, or June 30, 2024, as applicable, in the case of balance sheet data. The unaudited pro forma historical financial data is presented for illustrative purposes only and are not necessarily indicative of the financial position that would have existed or the financial results that would have occurred if this offering and the Reorganization Transactions had been consummated on the dates indicated, nor are they necessarily indicative of the financial position or results of our operations in the future. The pro forma adjustments, as described in the notes to the unaudited pro forma condensed combined financial statements, are preliminary and based upon currently available information and certain assumptions that our management believes are reasonable. The summary historical consolidated financial data is qualified in its entirety by, and should be read in conjunction with, the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section included in this prospectus and the consolidated financial statements and related notes and other financial information included in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the following information. Historical results are not necessarily indicative of results that may be expected for any future period.
You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our historical combined financial statements and our unaudited pro forma condensed combined financial statements and the notes thereto included elsewhere in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed combined financial statements include more detailed information regarding the basis of presentation for the following information.
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The following table presents non-GAAP financial measures, Adjusted EBITDAX and Distributable Cash from Operations, which we use in evaluating the financial performance of our business. These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain these measures below and reconcile them to the most directly comparable financial measures calculated and presented in accordance with GAAP.
| Predecessor Combined Historical | Pro Forma | |||||||||||||||||||||||
| Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||
| (in thousands, except per unit amounts) | 2024 | 2023 | 2023 | 2022 | ||||||||||||||||||||
Statement of operations information: | ||||||||||||||||||||||||
Revenue: | ||||||||||||||||||||||||
Oil and natural gas sales, net(1) | $ | 24,529 | $ | 27,960 | $ | 54,133 | $ | 94,646 | $ | 24,529 | $ | 54,133 | ||||||||||||
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Total revenue, net | 24,529 | 27,960 | 54,133 | 94,646 | 24,529 | 54,133 | ||||||||||||||||||
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Operating Expenses: | ||||||||||||||||||||||||
Lease operating | 6,397 | 6,839 | 13,949 | 14,164 | 6,397 | 13,949 | ||||||||||||||||||
Production and ad valorem taxes | 3,266 | 4,043 | 7,508 | 11,393 | 3,266 | 7,508 | ||||||||||||||||||
Depletion, depreciation and amortization | 7,163 | 13,275 | 28,801 | 30,917 | 7,163 | 28,801 | ||||||||||||||||||
Accretion | 116 | 113 | 227 | 224 | 116 | 227 | ||||||||||||||||||
Abandonment | 1,973 | 2,896 | 2,932 | 1,143 | 1,973 | 2,932 | ||||||||||||||||||
Impairment of oil and natural gas properties(2) | — | — | 111,871 | — | — | 111,871 | ||||||||||||||||||
General and administrative | 4,486 | 4,070 | 7,830 | 7,352 | 4,486 | 7,830 | ||||||||||||||||||
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|
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|
| |||||||||||||
Total operating expenses | 23,401 | 31,236 | 173,118 | 65,193 | 23,401 | 173,118 | ||||||||||||||||||
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| |||||||||||||
Income (loss) from operations | 1,128 | (3,276 | ) | (118,985 | ) | 29,453 | 1,128 | (118,985 | ) | |||||||||||||||
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Other Income (Expense): | ||||||||||||||||||||||||
Gain (loss) on commodity derivatives | (6,992 | ) | 3,573 | 1,604 | (27,271 | ) | (6,992 | ) | 1,604 | |||||||||||||||
Interest expense, net | (4,330 | ) | (4,193 | ) | (8,867 | ) | (4,913 | ) | (4,330 | ) | (8,867 | ) | ||||||||||||
Loss from retirement of long-term debt | — | (1,089 | ) | (1,080 | ) | — | — | (1,080 | ) | |||||||||||||||
Investment income(3) | — | — | — | — | 2,304 | 9,675 | ||||||||||||||||||
Gain (loss) on sale of assets | (23 | ) | 1,203 | 1,240 | 7 | (23 | ) | 1,240 | ||||||||||||||||
Other gain (loss) | 90 | 1,293 | 1,652 | (862 | ) | 90 | 1,652 | |||||||||||||||||
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Total other income (expense) | (11,255 | ) | 787 | (5,451 | ) | (33,039 | ) | (8,951 | ) | 4,224 | ||||||||||||||
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Net income (loss) before income taxes | (10,127 | ) | (2,489 | ) | (124,436 | ) | (3,586 | ) | (7,823 | ) | (114,761 | ) | ||||||||||||
Income tax benefit (provision) | — | — | — | — | 1,641 | 24,138 | ||||||||||||||||||
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Net Loss | $ | (10,127 | ) | $ | (2,489 | ) | $ | (124,436 | ) | $ | (3,586 | ) | $ | (6,182 | ) | $ | (90,623 | ) | ||||||
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| Predecessor Combined Historical | Pro Forma | |||||||||||||||||||||||
| Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||
| (in thousands, except per unit amounts) | 2024 | 2023 | 2023 | 2022 | ||||||||||||||||||||
Pro forma information: | ||||||||||||||||||||||||
Pro forma net loss(3) | $ | (10,127 | ) | $ | (2,489 | ) | $ | (124,436 | ) | $ | (3,586 | ) | $ | (6,182 | ) | $ | (90,623 | ) | ||||||
Pro forma net loss per Class A Common Unit | ||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||
Pro forma weighted-average number of Class A Common Units | ||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||
Balance sheet information (end of period): | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 9,170 | $ | 10,468 | $ | 15,439 | $ | 6,561 | $ | 9,170 | $ | 15,439 | ||||||||||||
Total oil and natural gas properties | $ | 187,397 | $ | 312,703 | $ | 194,658 | $ | 317,774 | $ | 187,397 | $ | 194,658 | ||||||||||||
Total assets | $ | 213,454 | $ | 345,368 | $ | 233,985 | $ | 346,926 | $ | 249,851 | $ | 280,979 | ||||||||||||
Long-term debt | $ | 48,610 | $ | 53,957 | $ | 49,765 | $ | 52,000 | $ | 48,610 | $ | 49,765 | ||||||||||||
Total liabilities | $ | 93,023 | $ | 92,864 | $ | 103,427 | $ | 91,932 | $ | 103,337 | $ | 116,314 | ||||||||||||
Total members’ equity | $ | 120,431 | $ | 252,504 | $ | 130,588 | $ | 254,994 | $ | 146,514 | $ | 164,665 | ||||||||||||
Net cash provided by (used by): | ||||||||||||||||||||||||
Operating activities | $ | (2,391 | ) | $ | 4,684 | $ | 14,093 | $ | 20,829 | $ | (2,391 | ) | $ | 23,768 | ||||||||||
Investing activities | $ | (2,248 | ) | $ | (7,733 | ) | $ | (9,099 | ) | $ | (15,278 | ) | $ | (2,248 | ) | $ | (9,099 | ) | ||||||
Financing activities | $ | (1,630 | ) | $ | 6,956 | $ | 3,884 | $ | (19,408 | ) | $ | (1,630 | ) | $ | (3,884 | ) | ||||||||
Other financial information: | ||||||||||||||||||||||||
Adjusted EBITDAX(4) | $ | 10,211 | $ | 12,056 | $ | 24,076 | $ | 29,708 | $ | 10,211 | $ | 33,751 | ||||||||||||
Distributable Cash from Operations(5) | $ | 5,987 | $ | (134 | ) | $ | 5,689 | $ | 11,743 | $ | 5,987 | $ | 15,364 | |||||||||||
| (1) | Impairment for the year ended December 31, 2023 and the twelve months ended June 30, 2024 was primarily due to a decrease in the value of proved oil and natural gas reserves as a result of lower oil and natural gas prices at December 31, 2023 and June 30, 2024, respectively, as well as SEC guidelines on development pace. For the year ended December 31, 2023, oil and natural gas prices calculated in accordance with SEC guidelines decreased by 16.5% and 58.5%, respectively, as compared to the year ended December 31, 2022. |
| (2) | Adjustment to reflect distributions received from PSI representing a return on investment during the six months ended June 30, 2024 and the year ended December 31, 2023. |
| (3) | Pro forma net loss reflects a pro forma income tax benefit of $1.6 million for the six months ended June 30, 2024 and $24.1 million for the year ended December 31, 2023, respectively, all of which is associated with the income tax effects of the corporate reorganization described under “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction” and this offering. Our predecessor was not subject to U.S. federal income tax at an entity level. As a result, the consolidated net loss |
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| in our historical financial statements does not reflect the tax expense or benefit we would have incurred if we were subject to U.S. federal income tax at an entity level during such periods. |
| (4) | Adjusted EBITDAX is not a financial measure calculated in accordance with U.S. generally accepted accounting principles (“GAAP”), but we believe it provides important perspective regarding our operating results. “—Non-GAAP Financial Measures” below contains a description of Adjusted EBITDAX and a reconciliation to our net income, our most directly comparable financial measure calculated in accordance with GAAP. |
| (5) | Distributable Cash from Operations is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our ability to internally fund our exploration and development activities, pay distributions and to service or incur additional debt. “—Non-GAAP Financial Measures” below contains a description of Distributable Cash from Operations and a reconciliation to net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
Adjusted EBITDAX
We include in this prospectus the non-GAAP financial measure Adjusted EBITDAX and provide our calculation of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss), our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDAX as net income (loss) before (1) interest expense, net of interest income, (2) income tax provision, (3) depreciation, depletion and amortization, (4) impairment expenses, (5) accretion of discount on asset retirement obligations, (6) exploration expenses, (7) unrealized (gains) losses on commodity derivative contracts, (8) non-cash incentive compensation, (9) non-cash (gain) loss on investment in PSI, (10) abandonment expenses, and (11) certain other non-cash expenses.
We believe Adjusted EBITDAX is useful because it allows us 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 exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX 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. Adjusted EBITDAX 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. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.
Distributable Cash from Operations
Distributable Cash from Operations is not a measure of net income (loss), our most directly comparable financial measure, calculated and presented in accordance with GAAP. Distributable Cash from Operations is a supplemental non-GAAP financial measure used by our management and by external users of our financial statements, such as investors, lenders and others (including industry analysts and rating agencies who will be using such measure), to assess our ability to internally fund our exploration and development activities, pay distributions and to service or incur additional debt. We define Distributable Cash from Operations as Adjusted EBITDAX, including dividends, less (1) cash interest expense, net of interest income, (2) development costs net of divestiture proceeds, (3) acquisition costs, (4) cash income tax payments, (5) reimbursements of expenses and payment of fees to our general partner and its affiliates and (6) certain other cash expenses (“Distributable Cash from Operations”). Development costs include all of our capital expenditures made for oil and natural gas properties, other than acquisitions, net of any proceeds from divestitures. Distributable Cash from Operations will not reflect changes in working capital balances.
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Distributable Cash from Operations is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measure most directly comparable to Distributable Cash from Operations is net income (loss). Distributable Cash from Operations should not be considered as an alternative to, or more meaningful than, net income (loss).
Available Cash will include Distributable Cash from Operations plus net proceeds of this offering to the extent not designated as a reserve for general partnership purposes, including in order to pay distributions on our Class A Common Units, if needed, and payment of indebtedness.
Reconciliations of Adjusted EBITDAX and Distributable Cash from Operations to GAAP Financial Measures
The following table presents our reconciliation of the non-GAAP financial measures Adjusted EBITDAX and Distributable Cash from Operations to the GAAP financial measure of net income (loss) for each of the periods indicated.
| Predecessor Combined Historical | Pro Forma | |||||||||||||||||||||||
| Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||
| (in thousands) | 2024 | 2023 | 2023 | 2022 | ||||||||||||||||||||
Net loss | $ | (10,127 | ) | $ | (2,489 | ) | $ | (124,436 | ) | $ | (3,586 | ) | $ | (6,182 | ) | $ | (90,623 | ) | ||||||
Interest expense, net of interest income | 4,330 | 4,193 | 8,867 | 4,913 | 4,330 | 8,867 | ||||||||||||||||||
Income tax provision (benefit) | — | — | — | — | (1,641 | ) | (24,138 | ) | ||||||||||||||||
Depreciation, depletion and amortization |
| 7,163 |
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| 13,275 |
| 28,801 | 30,917 | 7,163 | 28,801 | ||||||||||||||
Impairment of oil and natural gas properties | — | — | 111,871 | — | — | 111,871 | ||||||||||||||||||
Accretion | 116 | 113 | 227 | 224 | 116 | 227 | ||||||||||||||||||
Exploration expenses | — | — | — | — | — | — | ||||||||||||||||||
Non-cash gain (loss) on commodity derivatives |
| 6,756 |
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| (5,932 | ) | (5,266 | ) | (3,903 | ) | 6,756 | (5,266 | ) | |||||||||||
Non-cash incentive compensation expenses |
| — |
|
| — |
| — | — | — | — | ||||||||||||||
Non-cash (gain) loss on extinguishment of debt |
| — |
|
| — |
| 1,080 | — | — | 1,080 | ||||||||||||||
Non-cash (gain) loss on investment in PSI |
| — |
|
| — |
| — | — | (2,304 | ) | — | |||||||||||||
Abandonment | 1,973 | 2,896 | 2,932 | 1,143 | 1,973 | 2,932 | ||||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||
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Adjusted EBITDAX | $ | 10,211 | $ | 12,056 | $ | 24,076 | $ | 29,708 | $ | 10,211 | $ | 33,751 | ||||||||||||
Cash interest expense, net of interest income | (1,988 | ) | (4,474 | ) | (9,306 | ) | (2,875 | ) | (1,988 | ) | (9,306 | ) | ||||||||||||
Development costs(1) | (2,236 | ) | (7,716 | ) | (9,081 | ) | (15,090 | ) | (2,236 | ) | (9,081 | ) | ||||||||||||
Acquisition costs | — | — | — | — | — | — | ||||||||||||||||||
Cash income tax payments | — | — | — | — | — | — | ||||||||||||||||||
Reimbursement of general partner expenses | — | — | — | — | — | — | ||||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||
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Distributable Cash from Operations | $ | 5,987 | $ | (134 | ) | $ | 5,689 | $ | 11,743 | $ | 5,987 | $ | 15,364 | |||||||||||
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| (1) | Development costs include all of our capital expenditures for oil and natural gas properties, other than acquisitions, net of proceeds from divestitures. |
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Reconciliation of PV-10 to Standardized Measure
PV-10 represents the present value of estimated future cash inflows from oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. PV-10 is a financial measure not prepared in accordance with GAAP that generally differs from a measure under GAAP known as the standardized measure of discounted future net cash flows (“Standardized Measure”) in that PV-10 is calculated without consideration of future income taxes on future net revenues. Additionally, the calculation of PV-10 does not give effect to derivatives transactions. We believe the presentation of the PV-10 value of our oil and natural gas properties is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. We believe the use of a pretax measure provides greater comparability of assets when evaluating companies because the timing and quantification of future income taxes is dependent on company-specific factors, many of which are difficult to determine. For these reasons, we use and believe the industry generally uses the PV-10 as a measure to compare the relative size and value of reserves held by companies without regard to the specific tax characteristics of such entities. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for Standardized Measure as defined under GAAP.
Due to the absence of income taxes in our calculations of Standardized Measure, our PV-10 has historically been computed on the same basis as our Standardized Measure, the most comparable measure under GAAP; however, as a result of this offering and the election of Peak Resources LP to be taxed as a corporation, our future presentations of PV-10 may require a reconciliation to Standardized Measure because our Standardized Measure for future periods will include the effects of income taxes.
Investors should be cautioned that neither PV-10 nor Standardized Measure of proved reserves represents an estimate of the fair market value of our proved reserves. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.
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Summary Reserve, Production and Operating Data
Summary Reserve Data
The following table summarizes our estimated net oil and natural gas reserves as of December 31, 2023 and December 31, 2022. Estimates as of December 31, 2023 are based on a report prepared by Cawley Gillespie for Peak Resources LP and filed as Exhibit 99.1 to the registration statement of which this prospectus forms a part. Estimates as of December 31, 2022 represent a summation of the reports prepared by Cawley Gillespie for Peak E&P and PBLM and filed as Exhibits 99.4 and 99.5, respectively, to the registration statement of which this prospectus forms a part. Our reserves are reported in two streams: oil and natural gas. The economic value of the NGLs is included in our natural gas price and reserves. All of these reserve estimates were prepared in accordance with the SEC’s rule regarding reserve reporting currently in effect. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business and Properties—Oil and Natural Gas Data—Reserves” in evaluating the material presented below.
| As of December 31, 2023(1)(2) | As of December 31, 2022(3) | |||||||
Proved Reserves: | ||||||||
Oil (MBbls) | 9,515 | 7,411 | ||||||
Natural Gas (MMcf) | 40,392 | 36,548 | ||||||
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Total Proved Reserves (Mboe) | 16,247 | 13,502 | ||||||
Proved Developed Reserves: | ||||||||
Oil (MBbls) | 4,579 | 5,700 | ||||||
Natural Gas (MMcf) | 21,327 | 23,875 | ||||||
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Total Proved Developed Reserves (Mboe) | 8,134 | 9,679 | ||||||
Proved Undeveloped Reserves: | ||||||||
Oil (MBbls) | 4,936 | 1,711 | ||||||
Natural Gas (MMcf) | 19,065 | 12,673 | ||||||
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Total Proved Undeveloped Reserves (Mboe) | 8,114 | 3,823 | ||||||
| (1) | Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil volumes, the average WTI posted price of $78.22 per barrel as of December 31, 2023, was adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. For natural gas volumes, the average Henry Hub spot price of $2.637 per MMBtu as of December 31, 2023, was similarly adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. All prices are held constant throughout the lives of the properties. |
| (2) | The development plan associated with our 2023 proved reserves includes the use of cash flow from operations as well as a portion of the estimated net proceeds from this offering. |
| (3) | Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil volumes, the average WTI posted price of $93.67 per barrel as of December 31, 2022, was adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. For natural gas volumes, the average Henry Hub spot price of $6.358 per MMBtu as of December 31, 2022, was similarly adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. All prices are held constant throughout the lives of the properties. |
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The following table summarizes the PV-10 of our proved reserves as of December 31, 2023. For more information on how we calculate PV-10 and reconcile PV-10 to Standardized Measure, its nearest GAAP measure, see “—Non-GAAP Financial Measures—Reconciliation of PV-10 to Standardized Measure.”
| PV-10 as of December 31, 2023 ($ in thousands) | ||||
Total Proved Reserves | $ | 186,486 | ||
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| |||
Proved Developed Reserves | $ | 112,667 | ||
Proved Undeveloped Reserves | $ | 73,819 | ||
Selected Production and Operating Statistics
| Predecessor Combined Historical | ||||||||||||
| Six Months Ended June 30, | Year Ended December 31, | |||||||||||
| 2024 | 2023 | 2022 | ||||||||||
Summary Historical Operating Data: | ||||||||||||
Production and Operating Data: | ||||||||||||
Net production volumes: | ||||||||||||
Oil (MBbls) | 288 | 625 | 809 | |||||||||
Natural gas (MMcf) | 1,269 | 2,705 | 2,982 | |||||||||
Total (Mboe) | 500 | 1,076 | 1,306 | |||||||||
Average net production (Boe/d) | 2,745 | 2,947 | 3,578 | |||||||||
Average sales prices(1): | ||||||||||||
Oil sales (per Bbl) | $ | 76.50 | $ | 76.04 | $ | 93.27 | ||||||
Oil sales with derivative settlements (per Bbl) | $ | 72.18 | $ | 70.12 | $ | 66.06 | ||||||
Natural gas (per Mcf) | $ | 1.98 | $ | 2.45 | $ | 6.44 | ||||||
Natural gas sales with derivative settlements (per Mcf) | $ | 2.76 | $ | 2.46 | $ | 3.37 | ||||||
Average price per Boe | $ | 49.10 | $ | 50.33 | $ | 72.48 | ||||||
Average price per Boe with derivative settlements | $ | 48.63 | $ | 46.92 | $ | 48.61 | ||||||
Average unit costs per Boe: | ||||||||||||
Lease operating | $ | 12.80 | $ | 12.97 | $ | 10.85 | ||||||
Production and ad valorem taxes | $ | 6.54 | $ | 6.98 | $ | 8.72 | ||||||
Depletion, depreciation and amortization | $ | 14.34 | $ | 26.78 | $ | 23.68 | ||||||
Accretion | $ | 0.23 | $ | 0.21 | $ | 0.17 | ||||||
Abandonment | $ | 3.95 | $ | 2.73 | $ | 0.88 | ||||||
Impairment of oil and natural gas properties | — | $ | 104.00 | — | ||||||||
General and administrative | $ | 8.98 | $ | 7.28 | $ | 5.63 | ||||||
| (1) | Average sales prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains or losses on cash settlements for commodity derivative transactions and premiums paid or received on options, if any, that settled during the period. |
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Selected Projected Financial and Production Information
The following table sets forth projected production of the Company’s oil and natural gas reserves based on the projected drilling schedule presented herein:
| Projected Average Daily Production (1) | ||||||||||||||||
| Year Ending December 31, | ||||||||||||||||
| 2024 (Estimated) | 2025 (Estimated) | 2026 (Estimated) | 2027 (Estimated) | |||||||||||||
Average daily oil production (Bbl/d) | 1,499 | 3,047 | 4,410 | 4,531 | ||||||||||||
Average daily natural gas production (Mcf/d) | 7,393 | 9,814 | 12,162 | 13,653 | ||||||||||||
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Total average daily production (Boe/d) | 2,731 | 4,683 | 6,437 | 6,806 | ||||||||||||
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| (1) | Represents timing for production when revenue is actually paid to the Company. Well production estimates are based on type curves for the current development plan, which uses a portion of the proceeds from the offering. |
Based on the projected production information set forth above, the following table sets forth our projected revenue, PSI dividends declared, projected PSI dividends and estimated Adjusted EBITDAX for the periods presented:
| Twelve Months Ending December 31, | ||||||||
| (in thousands) | 2024 (Estimated) | 2025 (Estimated) | ||||||
Projected revenue | $ | 48,310 | $ | 92,147 | ||||
PSI dividend paid | $ | 2,304 | $ | — | ||||
Projected PSI dividend(1) | $ | 6,440 | $ | 6,440 | ||||
Estimated Adjusted EBITDAX(2) | $ | 26,178 | $ | 60,414 | ||||
| (1) | Projected PSI dividend for the year ending December 31, 2024 includes PSI dividend of $2.3 million to the Company. |
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| (2) | The following table presents our reconciliation of the non-GAAP financial measure of estimated Adjusted EBITDAX for the periods indicated. We do not forecast certain estimated non-cash items as components of our estimated Adjusted EBITDAX calculation because they cannot be accurately estimated due to the uncertainty regarding timing and estimates of such items. Forecasted depreciation, depletion and amortization is calculated using 2023 depletion rates multiplied by estimated production for each applicable period. Additionally, estimated Adjusted EBITDAX includes historically paid or estimated PSI dividends to be paid. |
| Forecasted | ||||||||
| Twelve Months Ending December 31, | ||||||||
| (in thousands) | 2024 (Estimated) | 2025 (Estimated) | ||||||
Projected net income (loss) | $ | (871 | ) | $ | 15,498 | |||
Interest expense, net of interest income | 6,366 | 1,179 | ||||||
Income tax provision (benefit) | (232 | ) | 4,120 | |||||
Depreciation, depletion and amortization | 18,678 | 39,367 | ||||||
Impairment of oil and natural gas properties | — | — | ||||||
Accretion | 233 | 250 | ||||||
Exploration expenses | — | — | ||||||
Non-cash gain (loss) on commodity derivatives | — | — | ||||||
Non-cash incentive compensation expenses | — | — | ||||||
Non-cash (gain) loss on extinguishment of debt | — | — | ||||||
Non-cash (gain) loss on investment in PSI | — | — | ||||||
Abandonment | 2,004 | — | ||||||
Other (gain) loss | — | — | ||||||
Estimated Adjusted EBITDAX | $ | 26,178 | $ | 60,414 | ||||
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Investing in our Class A Common Units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our Class A Common Units. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. Additionally, new risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our financial performance.
If any of the following risks actually occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our Class A Common Units, the trading price of our Class A Common Units could decline and our unitholders could lose all or part of their investment.
Risks Related to Cash Distributions on our Class A Common Units
Cash distributions may fluctuate with our performance, and we may not have sufficient cash available to pay any quarterly distribution on our Class A Common Units.
We may not have sufficient cash available each quarter to pay distributions on our Class A Common Units. Our partnership agreement requires us to distribute all of our Available Cash each quarter. We define “Available Cash” as our cash on hand at the end of each quarter, plus certain distributions or dividends received after the end of the quarter, plus certain working capital borrowings and proceeds from this offering if determined by our general partner, less cash reserves established by our general partner, including for the proper conduct of our business, such as for capital expenditures, acquisitions, debt service, compliance with law and loan agreements and future distributions. As a result, to the extent there is no Available Cash, our partnership agreement does not require us to pay distributions on our Class A Common Units on a quarterly basis or otherwise. The amount of Available Cash that we distribute to our Class A Common Unitholders will depend principally on the cash we generate from operations, which will depend on, among other factors:
| • | the amount of oil and natural gas we produce; |
| • | the prices at which we sell our oil and natural gas production; |
| • | the amount and timing of settlements on our commodity derivative contracts; |
| • | the level of our capital expenditures, including scheduled and unexpected maintenance expenditures; |
| • | the level of our operating costs, including payments to our general partner and its affiliates for general and administrative expenses; |
| • | the amount of cash dividends we receive from our investment in PSI; |
| • | the restrictive covenants in our Existing Credit Agreement, and the New Credit Facility, if applicable, and other agreements governing indebtedness that limit our ability to pay dividends or distributions in respect of our equity; |
| • | the cost of acquisitions, if any; |
| • | fluctuations in our and our subsidiaries’ working capital needs; |
| • | our debt service requirements and the level of our interest expenses, which will depend on the amount of our outstanding indebtedness and the applicable interest rate; and |
| • | the amount of cash reserves established by our general partner in its discretion for the proper conduct of our business. |
Because of all these factors, we cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our initial target quarterly distribution. The actual amount
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of cash that is available for distribution to our Class A Common Unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner. Furthermore, the amount of Available Cash for distribution also depends on our cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make distributions of Available Cash during periods when we record losses for financial accounting purposes and may not make distributions of Available Cash during periods when we record net income for financial accounting purposes. To the extent our Distributable Cash from Operations is insufficient to pay our quarterly distributions, we may use cash on hand, including proceeds from this offering, to maintain or grow our cash distributions to our Class A Common Unitholders. In addition, the issuance of additional Class A Common Units, or the conversion of Class B Common Units, may be dilutive to our Class A Common Unitholders and, as a result, distributions of Available Cash to our Class A Common Unitholders may decrease.
The assumptions underlying the forecast of Available Cash for distribution to our Class A Common Unitholders we include in “Our Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results.
Our management’s forecast of Available Cash for distribution on our Class A Common Units set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDAX and Distributable Cash from Operations for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from those forecasted. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted quarterly distribution or any amount on our Class A Common Units, which may cause the market price of our Class A Common Units to decline materially.
The amount of our quarterly cash distributions from Available Cash, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution and could pay no distribution with respect to any particular quarter.
We cannot guarantee the payment of regular quarterly distributions. Our future business performance may be volatile, and our cash flows may be unstable. We will not have a minimum quarterly distribution. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our Class A Common Unitholders will vary significantly from quarter to quarter and may be zero. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”
Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to Class A Common Unitholders.
Our partnership agreement allows our general partner to establish cash reserves from Available Cash that in its reasonable discretion are necessary, among other things, to fund our future capital and operating expenditures. In addition, our partnership agreement permits our general partner to reduce Available Cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of distributions to Class A Common Unitholders.
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Risks Related to Our Business and the Oil and Natural Gas Industry
Oil and natural gas prices are volatile. A substantial or extended decrease in prices of these commodities could adversely affect our business, financial condition, results of operations, ability to meet our financial commitments, ability to make our planned capital expenditures and distributions.
Our revenues, operating results, cash flows from operations, distributions, future growth rates, and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Oil and natural gas prices historically have been volatile and likely will continue to be volatile in the future, especially given current world geopolitical conditions. The price volatility could affect the amount of our cash flows available for capital expenditures, the costs of conducting and maintaining operations, and our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to:
| • | worldwide and regional economic conditions impacting the supply and demand for oil and natural gas; |
| • | the level of global oil and natural gas exploration and production; |
| • | the ability of and actions taken by members of OPEC and other oil-producing nations in connection with their arrangements to maintain oil prices and production controls; |
| • | the impact on worldwide economic activity of an epidemic, outbreak or other public health events; |
| • | localized and global supply and demand fundamentals and transportation availability; |
| • | weather conditions across the globe; |
| • | market uncertainty due to political conditions or conflicts in oil and natural gas-producing regions, including the Middle East; |
| • | technological advances affecting energy consumption and energy supply; |
| • | speculative trading in commodity markets, including expectations about future commodity prices; |
| • | the proximity of our oil and natural gas production to, and the availability, capacity and cost of, pipelines and other transportation and storage facilities, and other factors that result in differentials to benchmark prices; |
| • | the impact of worldwide energy conservation measures, alternative fuel requirements and climate change-related legislation, policies, initiatives and developments; |
| • | the price and availability of alternative fuels; |
| • | the cost of exploring for, developing, producing, transporting, and marketing oil and natural gas; |
| • | stockholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas or limit sources of funding for the energy sector; |
| • | domestic, local and foreign governmental laws, regulation and taxes; and |
| • | overall domestic and global economic conditions. |
These and other factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements accurately. Changes in oil and natural gas prices have a significant impact on the amount of oil and natural gas that we can produce economically, the value of our reserves and on our cash flows. Any substantial or extended decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations, ability to meet our financial commitments and fund planned capital expenditures and distributions.
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Unless we replace the reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations, results of operations and our ability to make distributions.
We may be unable to pay distributions without substantial capital expenditures that maintain and grow our asset base. Oil and natural gas production is generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing reserves, our reserves will decline as those reserves are produced. Our future reserves and production and, therefore, our cash flow and ability to make distributions, are highly dependent on our success in efficiently developing, optimizing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production on economically acceptable terms, which would adversely affect our business, financial condition and results of operations and distributions.
If commodity prices decline and remain depressed for a prolonged period, production from a significant portion of our properties may become uneconomic and cause downward adjustments of our reserve estimates and write downs of the value of such properties, which may adversely affect our financial condition and our ability to make distributions.
Lower commodity prices over extended periods of time may render many of our development projects uneconomic and result in a downward adjustment of our reserve estimates and also possibly cause us to shut in or plug and abandon certain wells, which would negatively impact our ability to borrow to fund our operations or make distributions. As a result, we may reduce the amount of distributions paid or cease paying distributions. In addition, a significant or sustained decline in commodity prices could hinder our ability to effectively execute our hedging strategy. For example, during a period of declining commodity prices, we may enter into commodity derivative contracts at relatively unattractive prices in order to mitigate a potential decrease in our cash flow. Furthermore, if commodity prices fall below certain levels, our production, reserves and cash flows will be adversely impacted and we may be required to record additional impairments, which could be material. While we currently have a fixed term loan under our Existing Credit Agreement, in the future we may refinance our debt into a revolving reserve-based loan, such as under the New Credit Facility, which we are in the process of negotiating. Under such a loan structure, lower oil and natural gas prices may result in a reduction in the borrowing base under, which may be determined at the discretion of the lenders.
Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
We have specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, availability and cost of capital, drilling and production costs, availability of drilling services and equipment, availability and cost of sand and other proppant used in hydraulic fracturing operations, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution and disposal systems, access to and availability of wastewater water disposal systems, regulatory approvals, the cooperation of other working interest owners and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil and natural gas from these or any other drilling locations. As such, our actual drilling activities may materially differ from those presently identified.
In addition, the leases covering our identified drilling locations will expire at the end of their respective primary terms unless production is established in paying quantities under the units that include all or a portion of the respective leases, the leases are held beyond their primary terms under continuous drilling provisions, or the
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leases, or some of them, are renewed. 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. If our leases expire and we are unable to renew the leases, we will lose our right to develop the affected properties and our actual drilling activities may differ materially from our current expectations. As such, our future oil and natural gas reserves and production, including our drilling activities, and therefore, our future cash flows and income are highly dependent on successfully developing our undeveloped leasehold acreage.
As a result of the limitations described in this prospectus, we may be unable to drill certain of our identified locations. In addition, although we plan to fund our drilling program with cash flow from operations and proceeds from this offering, if our cash flows are less than we expect or we alter our drilling plans, we may be required to issue new debt or equity securities in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “Our development projects and potential future acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful, may not result in production or additions to our estimated proved reserves and could result in a downward revision of our estimated proved reserves, which in turn could have a material adverse effect on our ability to raise additional capital or incur additional indebtedness.
A portion of our identified horizontal drilling locations are based on our management’s internal estimates and were not based on evaluations prepared by Cawley Gillespie.
Approximately 696 gross (176 net) of our 1,770 gross (530 net) identified horizontal drilling locations were based on our management’s internal estimates and not based on evaluations of Cawley Gillespie. While we feel that management’s internal estimates were based upon the same guidelines as used within the Cawley Gillespie evaluation, being production performance-based methods, material balance-based methods, volumetric-based methods and analogy, these locations ultimately were not audited by Cawley Gillespie. As a result, these estimates have greater uncertainty than those identified horizontal drilling locations evaluated by Cawley Gillespie.
Our development projects and potential future acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.
The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures for development drilling and completion activities. Funding sources for our capital expenditures have historically included borrowings under our Existing Credit Agreement, cash from our Existing Owners and cash flow from operating activities. A number of factors could cause our cash flow to be less than we expect, including the results of our drilling and completion program. Moreover, our capital budget is based on a number of assumptions, including expected elections by working interest partners, drilling and completion costs, midstream service costs, oil and natural gas prices, and drilling results, and are therefore subject to change. If our cash flows are less than we expect, we decide to pursue acquisitions, or we change our capital budget, we may be required to issue debt or equity securities to consummate such acquisitions or fund our drilling and completion program. The incurrence of additional indebtedness, either through the issuance of additional debt securities, refinancing the Existing Credit Agreement with the New Credit Facility, or otherwise, would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund capital expenditures, our development plan, acquisitions and cash distributions to unitholders. Additionally, the market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. The issuance of additional equity securities may be dilutive to our unitholders. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other
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things: oil and natural gas prices; actual drilling results; the availability and cost of drilling rigs and labor and other services and equipment; the availability, cost and adequacy of midstream gathering, processing, compression and transportation infrastructure; and regulatory, technological and competitive developments.
Our cash flow from operations and access to capital are subject to a number of variables, including:
| • | the prices at which our oil and natural gas are sold; |
| • | the amount of our reserves; |
| • | the volume of hydrocarbons we are able to produce from existing wells and future wells; |
| • | our ability to successfully drill and complete new wells; |
| • | our ability to acquire, locate and produce economically new reserves; |
| • | the amount of our operating expenses; |
| • | the amount of debt service; |
| • | the extent and levels of our derivative activities; and |
| • | our ability to access the debt and equity capital markets, obtain financing under our New Credit Facility or sell non-core assets. |
If our revenues or cash flows decrease as a result of lower commodity prices, increases in interest rates or capital expenditures, operational difficulties, declines in reserves or for any other reason we may have limited ability to obtain the capital necessary to develop our existing undeveloped properties or to make acquisitions or sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations is insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in our reserves and production and could materially and adversely affect our business, financial condition and results of operations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
Our U.S. producing properties are concentrated in the Powder River Basin, making us vulnerable to risks associated with operating in a single geographic area.
As a result of our geographic concentration in the Powder River Basin, adverse industry developments in our primary operating area could have a greater impact on our financial condition and results of operations than if our exploration and development operations were more geographically diverse. We may be disproportionately exposed to the impact of regional supply and demand factors, governmental regulations, midstream capacity constraints, availability of facilities, services market limitations or interruption of the processing or transportation of crude oil, natural gas or NGLs, and extreme weather conditions and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities. In addition, fluctuations of supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Powder River 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, these fluctuations may result 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. Delays or interruptions caused by such adverse developments could have a material adverse effect on our financial condition and results of operations.
Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case recently in our operating areas, we are subject to increasing competition for drilling rigs,
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workover rigs, tubulars and other well equipment, services, supplies as well as increased labor costs and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their anticipated duration.
Demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years and may increase substantially in the future. Moreover, our competitors, including those operating in multiple basins, 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 have a negative effect on production volumes or significantly increase costs, which, in turn, could have a material adverse effect on our results of operations, liquidity and financial condition.
The unavailability, high cost or shortages of drilling rigs, fracking crews, equipment, raw materials, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, frac crews, pipe and other equipment, raw materials and supplies, including source water, sand and other proppant used in hydraulic fracturing operations, as well as for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with commodity prices or drilling activity in our areas of operation and in other shale basins in the United States, causing periodic shortages of supplies and needed personnel and rapid increases in costs. Increased drilling activity could materially increase the demand for and prices of these goods and services, and we could encounter rising costs and delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to conduct our drilling and development activities, which could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs could have a material adverse effect on our cash flow and profitability.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition, results of operations and cash distributions.
Our future financial condition and results of operations, and therefore our ability to make cash distributions to our unitholders, will depend on the success of our acquisition, development, optimization and exploitation activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable production.
Our decisions to purchase, develop, optimize or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Reserve estimates depend on many interpretations and assumptions. Any significant inaccuracies in reserve estimates or underlying interpretations or assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
| • | unexpected or adverse drilling conditions; |
| • | delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements including permitting requirements (including any such permits relating to water sourcing), limitations on or resulting from wastewater discharge and the disposal of exploration and production wastes, including subsurface injections; |
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| • | elevated pressure or irregularities in geological formations; |
| • | shortages of or delays in obtaining equipment and qualified personnel or in obtaining water or proppant for hydraulic fracturing activities; |
| • | facility or equipment failures or accidents; |
| • | lack of available gathering facilities or delays in construction of gathering facilities; |
| • | lack of available capacity on interconnecting transmission pipelines or other forms of transportation; |
| • | adverse weather conditions, such as cyclones, lightning storms, flooding, tornadoes, snow or ice storms and changes in weather patterns; |
| • | issues related to compliance with, or changes in, environmental and other governmental regulations; |
| • | environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of wastewater or brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment; |
| • | declines in oil and natural gas prices; |
| • | limited availability of financing at acceptable terms; |
| • | the availability and timely issuance of required governmental permits and licenses; |
| • | title issues or legal disputes regarding leasehold rights; and |
| • | other market limitations in our industry. |
We have a minority ownership position in PSI, a private company primarily operating in Colombia and a minority ownership position in PetroReconcavo, S.A., a company which operates in Brazil and is publicly listed on the Sao Paulo stock exchange.
The value of our minority ownership position in PSI and the amount of dividends which we may receive from PSI in the future is subject to a number of risks. Outside of risks relating to oil and gas operations, other risks include:
| • | termination of, or intervention in, concessions, rights or authorizations granted by the Colombian or Brazilian governments to us; |
| • | expropriation risk; |
| • | capital controls risk; |
| • | the recent social and political unrest, driven in many cases by populist groups, in the countries that PSI operates and has an interest in; |
| • | potential for armed conflict in the countries PSI operates and has an interest in; |
| • | fluctuation in inflation and exchange rates in Colombia and Brazil; |
| • | contract counterparty risk; |
| • | violations of the U.S. Foreign Corruption Act; |
| • | direct or indirect impact resulting from terrorist incidents or responses to such incidents, including the effect and availability of and premiums on insurance; |
| • | changes in the government or other changes in political conditions in Brazil and/or Colombia; and |
| • | the adoption of policies, regulations, or taxes which impact PSI’s or PetroReconcavo’s operations, cash flow or ownership of assets. |
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We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our growth potential.
Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in Distributable Cash from Operations. There is intense competition for acquisition opportunities in our industry and we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition, do so on commercially acceptable terms or obtain sufficient financing to do so. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.
In addition, our debt arrangements impose certain limitations on our ability to enter into mergers or business combination transactions and to make certain investments. Our debt arrangements also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements—Existing Credit Agreement.”
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.
Any of these factors could have a material adverse effect on our financial condition and results of operations.
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 liabilities, including, but not limited to, environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or may acquire in the future may not produce as projected. In connection with the assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practice, but such a review will not reveal all existing or potential problems. As a practical matter, in the course of our due diligence, inspections may not always be performed on every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a physical review is performed. We may be unable to negotiate contractual indemnities from any seller for liabilities arising from or attributable to the period prior to our purchase of the property. Additionally, in connection with certain acquisitions, 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.
Increased cost of capital could adversely affect our business.
Our business could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates. For example, interest rates rose throughout 2022 and 2023 and may continue to rise, and there can be no assurance as to what actions the Federal Reserve will take in the future. 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 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 activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.
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Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Certain of the properties we drill may not yield oil or natural gas in commercially viable quantities and, accordingly, will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of geologic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects.
We may incur losses as a result of title defects in the properties in which we invest.
The existence of material title defects can cause our title to fail, which would render a lease or other interest worthless, which can adversely affect the results of our operations and financial condition. In order to minimize our acquisition costs, we rely upon the judgment of experienced lease brokers or landmen, who are not licensed to provide a legal title opinion, to perform a review of title and examine the records in the field (i.e., in the appropriate governmental office) before attempting to acquire a lease or other interest. Failure of title on our leases or other interests in a DSU in which we have drilled a well is unlikely because we commission a drill site title opinion from a licensed oil and gas attorney to ensure that our interests are not burdened by any material title defects.
We own non-operating interests in properties that are operated by third parties and some of our leasehold acreage on which we currently control operations could potentially be challenged resulting in our loss of operatorship. As a result, we are unable, or may become unable, to control the operation and ultimate profitability of such properties.
As part of our business strategy, we seek to maintain operational control over the majority of our drilling, completion, and production activities. In Wyoming, operatorship is initially granted to the first working interest owner to successfully submit a State of Wyoming Application for Permit to Drill (“State APD”) for a given formation in a DSU, the requirements for which include:
| • | WOGCC approved spacing order; |
| • | surface owner consent; |
| • | well location plat; |
| • | drill plan; |
| • | well plan; |
| • | horizontal application; and |
| • | electrical certification. |
We strive to maintain control of operatorship on our properties; however, Chapter 3, Section 8(m) of the WOGCC’s rules on APDs contains a mechanism by which other working interest owners can challenge our State APDs based on multiple factors, including working interest ownership in the DSU, expertise & technical ability to drill and complete wells and contractual obligations. To date, we have never had one of our existing APDs challenged. We intend to continue to focus on controlling the operatorship of our leasehold through prompt APD submissions and renewals, but we cannot guarantee that we will be successful in maintaining it on all or a majority of our currently controlled properties.
Some of the properties in which we have an interest are in DSUs that are operated by other companies. We have limited ability to influence or control the success of drilling and development activities on properties
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operated by third parties. Some of the factors that are under the control of the third-party operator include, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures, and the use of suitable technology. In addition, the third-party operator’s operational expertise, financial resources and ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities. A third-party operator’s failure to effectively perform operations, act in ways that are favorable to us or abide by applicable agreements could reduce our production and revenues, negatively impact our liquidity, and cause us to spend capital in excess of our current plans, and, as a result, have a material adverse effect on our financial condition and operational results.
We may be forced to incur additional capital expenditures beyond our budgeted amounts and at levels above what we can afford due to the Wyoming forced pooling process and as a result of third-party owners’ ability or desire to participate in our development activities.
In the past we have used, and we expect to continue to use, the Wyoming “forced pooling” process to potentially increase our working interest in wells we propose to drill as operator on our acreage, which could lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well. In recent years, the collective working interest of third-party mineral and lease owners in our drilling units that have elected to participate in our proposed wells has been relatively low, especially compared to historical trends. As third-party owners focus more on the development of their own acreage and reserves within cashflow, we believe that third-party working interest owners may be less likely to bear their share of the costs of the proposed future wells we propose to drill on our acreage. Thus, our working interest in proposed wells may be much higher than it is today as we may be forced to absorb third party working interests, resulting in capital expenditures that are significantly higher than we have budgeted. To the extent we are unable to afford the additional capital expenditures from the increased working interests, our development plans may be altered.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We often own less than 100% of the working interest in the DSUs in which we conduct operations, with other parties owning the remaining portion of the working interest (“Non-Operating Working Interest Owner”). Financial risks are inherent in any operation where the cost of drilling, equipping, completing, and operating wells is shared by more than one party. As operator, we could be responsible for joint activity obligations of Non-Operating Working Interest Owners, such as nonpayment of expended costs. In addition, declines in oil and natural gas prices could increase the likelihood that some of these Non-Operating Working Interest Owners, particularly those that are smaller and less established, will be unwilling or unable fulfill their joint activity payment obligations. In the event that any of the Non-Operating Working Interest Owners do not pay their share of costs in a well, we would likely have to pay such costs and attempt to recoup said costs out of the Non-Operating Working Interest Owner’s share of the revenue from such well, which could adversely affect our financial position in a material way.
Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.
Changes in climate and/or changes in weather patterns may be associated with more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena could affect some, or all, of our operations. Our development, optimization and exploitation activities and equipment could be adversely affected by extreme weather conditions, particularly in our operating region, such as thunderstorms, cyclones and tornadoes, snow or ice storms, and both hold and cold temperature extremes, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also impact other areas of our operations, including access to our water sources and drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party
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services, such as gathering, processing, compression and transportation services. Similarly, weather conditions could potentially impact our supply-chain services as well as our product take-away capacity. In some cases, snowstorms can lead to road closures, requiring wells to be shut-in for various reasons and pausing workovers. Our suppliers and customers could also similarly be impacted by weather conditions, which could further impact costs of operations and our revenues. These constraints and the resulting shortages or high costs could delay or temporarily halt our production operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.
Declining general economic, business or industry conditions, including high inflation, may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, high inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. During the year ended December 31, 2022, the U.S. economy experienced the highest rate of inflation in the past 40 years. High inflation has been pervasive since 2022, increasing the cost of salaries, wages, supplies, material, freight and energy. We expect relatively higher pricing due to inflation continuing in the second half of 2024, resulting in higher costs. Though we have incorporated inflationary factors in our 2024 and 2025 business plans, inflation may outpace those assumptions. We continue to undertake actions and implement plans to strengthen our supply chain to mitigate these pressures and protect the requisite access to commodities and services. These supply chain constraints and inflationary pressures may continue to adversely impact our operating costs and if we are unable to manage our supply chain, it may impact our ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could impact our ability to distribute Available Cash. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines often lag and may not adjust downward in proportion to prices. If we are unable to recover higher costs through higher commodity prices, our revenues could be adversely impacted and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
We continue to take actions to mitigate supply chain and inflationary pressures. We are working closely with our suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical suppliers, which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient, which could have an adverse effect on our results of operations and financial condition. In addition, continued and escalating hostilities in the Middle East, continued hostility related to the Russian invasion of Ukraine, potential economic uncertainty in China leading to decreased demand, and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These and other factors, combined with volatile commodity prices and declining business and consumer confidence, may contribute to an economic slowdown and a recession. Recent growing concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States 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.
Events outside of our control, including an epidemic or outbreak of an infectious disease or the threat thereof, could have a material adverse effect on our business, liquidity, financial condition, results of operations, cash flows and ability to pay distributions.
We face risks related to epidemics, outbreaks or other public health events, or the threat thereof, that are outside of our control, and could significantly disrupt our business and operational plans and adversely affect our liquidity, financial condition, results of operations, cash flows and ability to pay distributions on our Class A Common Units. The COVID-19 pandemic resulted in unprecedented governmental actions in the United States
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and countries around the world, including, among other things, social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent and natural gas. Additionally, the effects of a similar pandemic might worsen the likelihood or the impact of other risks already inherent in our business. We believe that the known and potential impacts of a pandemic and related events include, but are not limited to, the following:
| • | disruption in the demand for natural gas and other petroleum products; |
| • | intentional project delays until commodity prices stabilize; |
| • | potentially higher borrowing costs in the future; |
| • | a need to preserve liquidity, which could result in a reductions, delays or changes in our capital expenditures; |
| • | liabilities resulting from operational delays due to decreased productivity resulting from stay-at-home orders affecting our workforce or facility closures resulting from the pandemic; |
| • | future asset impairments, including impairment of our natural gas properties and other property and equipment; and |
| • | infections and quarantining of our employees and the personnel of vendors, suppliers and other third parties. |
New outbreaks of other viruses could cause further commodity market volatility and resulting financial market instability, or any other event described above, and these are variables beyond our control that may adversely impact our operating cash flows, our ability to pay distributions and our ability to access the capital markets.
We use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk.
To mitigate the risk associated with volatile commodity prices and to satisfy the requirement under our Existing Credit Agreement, we hedge, on a rolling quarterly basis, a portion of our production volumes based on reasonably anticipated projected production of proved developed producing reserves that we are required to hedge, predominantly using swaps and collars. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk—Commodity Derivatives.” By using derivative instruments to economically hedge exposure to changes in commodity prices, we could limit the benefit we would receive from increases in the prices for oil and natural gas, which could have an adverse effect on our financial condition. Likewise, to the extent our production is not hedged, we may be materially and adversely impacted by declines in commodity prices, and our derivative arrangements may be inadequate to protect us from continuing and prolonged declines in commodity prices.
Changes in the fair value of commodity price derivatives are recognized currently in earnings. Realized and unrealized gains and losses on commodity derivatives are recognized in oil and natural gas revenues. Settlements of derivatives are included in cash flows from operating activities. While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under GAAP, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements.
Additionally, restrictive covenants in our Existing Credit Agreement or the New Credit Facility may hinder our ability to effectively execute our hedging strategy. On a rolling quarterly basis, based on reasonably
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anticipated projected production of proved developed producing reserves, we are required to hedge at least certain volumes. Notwithstanding the foregoing, no volumes are required to be hedged more than 12 months after the maturity of the Existing Credit Agreement. Additionally, our future development activities must be approved by the existing lender. See “Our Existing Credit Agreement contains restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements—Existing Credit Agreement.”
We also expose ourselves to credit risk due to the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make it unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by a counterparty to these derivative contracts when they become due could have a material adverse effect on our financial condition and results of operations. Further, we are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
The failure of our customers or working interest holders to meet their obligations to us may adversely affect our financial results.
Our ability to collect payments from the sale of oil and natural gas to our customers depends on the payment ability of our customer base, which includes several significant customers. If any one or more of our significant customers fail to pay us for any reason or otherwise satisfy their contractual obligations, we could experience a material loss. In addition, if any of our significant customers cease to purchase our oil and natural gas or reduce the volume of the oil and natural gas that they purchase from us, the loss or reduction could have a detrimental effect on our revenues and may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas.
We also face credit risk through joint interest receivables. Joint interest receivables arise from billing entities who own partial working interests in the wells we operate. Though we have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings, the inability or failure of working interest holders to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Derivatives reform legislation and related regulation could have an adverse effect on our ability to hedge risks associated with our business.
The Dodd-Frank Act, enacted in 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC has adopted rules that place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. These limitations could increase the costs to us of entering into, or lessen the availability of, derivative contracts to hedge or mitigate our exposure to volatility in oil and natural gas prices and other commercial risks affecting our business. The Dodd-Frank Act and CFTC rules will also require us, in connection with certain derivatives activities, to comply with clearing and trade execution requirements (or to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end user exception to the mandatory clearing, trade execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if
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any of our swaps do not qualify for the commercial end user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, 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 Dodd-Frank Act was intended, in part, to reduce the volatility of natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.
Reserve estimates depend on many interpretations and assumptions. Any significant inaccuracies in reserve estimates or underlying interpretations or assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves and future net cash flows from such reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. As noted in more detail below, any significant variances in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.
Furthermore, the SEC rules require that, subject to limited exceptions, PUD reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule may limit our potential to record additional PUD reserves as we pursue our drilling program. To the extent that natural gas and oil prices decline materially from current levels, such conditions could render uneconomic a number of our identified drilling locations, in which case we would be required to write down our PUD reserves if we do not drill those wells within the required five-year time frame. If we choose not to develop PUD reserves, or if we are not otherwise able to successfully develop them, then we will be required to remove the associated volumes from our reported reserves.
We present reserves for the Company as of December 31, 2023 in addition to reserves for Peak E&P and Peak BLM. The proved undeveloped reserves as of December 31, 2023 for the Company assume the use of a portion of the estimated net proceeds from the offering, together with cash from operations. Our actual use of funds in connection with our development plan may differ from the assumptions in the reserve report, which may cause our reserves in future periods to differ.
The preparation of reserve estimates requires the projection of production rates and the timing of development expenditures based on an analysis of available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Many of these factors are or may be beyond our control.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance, including any significant downward revisions to our existing reserve estimates, could materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve
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estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.
The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
The present value of future net cash flow from our proved reserves, or standardized measure, may not represent the current market value of our estimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil and natural gas 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. For example, our estimated proved reserves as of December 31, 2023 were calculated under the SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $2.637/MMBtu for natural gas and $78.22/Bbl for oil at December 31, 2023, which for certain periods during this period were substantially different from the available spot prices. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with Accounting Standards 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.
We depend upon two 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.
For the six months ended June 30, 2024, HF Sinclair Refining & Marketing LLC and WGR Operating, LP accounted for approximately 83.9% and 8.8% of our total revenues, respectively, excluding the impact of our commodity derivatives. For the year ended December 31, 2023, HF Sinclair Refining & Marketing LLC and Thunder Creek Gas Services, LLC accounted for approximately 87% and 11% of our total revenues, respectively, excluding the impact of our commodity derivatives. For the year ended December 31, 2022, HF Sinclair Refining & Marketing LLC and Thunder Creek Gas Services, LLC accounted for approximately 75% and 18% of our total revenues, respectively, excluding the impact of our commodity derivatives. No other purchaser accounted for more than 10% of our revenue during such periods. We do not have long-term contracts with our purchasers but rather we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, potentially including on a month-to-month basis, to a relatively small number of purchasers. We do not believe that the loss of a single purchaser would materially affect our business because there are numerous other potential purchasers in the area in which we sell our production. However, the loss of any one of these significant purchasers, our ability to sell our production to other purchasers on terms we consider acceptable, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could have a short-term impact on our financial condition, results of operations and ability to make distributions to our unitholders. We cannot assure you that any of our purchasers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. See “Business and Properties—Operations—Marketing and Customers.”
The availability of a ready market for any hydrocarbons we produce depends on numerous factors beyond our control, 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, water sourcing, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and natural gas sold in interstate commerce.
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We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions.
The oil and natural gas industry is intensely competitive, and we compete with companies that possess and employ financial, technical and personnel resources substantially greater than ours. Our ability to acquire additional properties and to exploit reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors in the Powder River Basin not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions.
The development of our estimated undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated undeveloped reserves may not be ultimately developed or produced.
As of December 31, 2023, approximately 50% of our total estimated proved reserves were classified as PUDs. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Estimated future development costs relating to the development of our PUDs at December 31, 2023 was approximately $122.5 million over the next five years. 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. Our ability to fund these expenditures is subject to a number of risks. See “Our development projects and potential future acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Delays in the development of our PUDs, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the PV-10 value of our estimated PUDs and future net cash flows estimated for such reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could cause us to have to reclassify some of our PUDs as unproved reserves. Furthermore, there is no certainty that we will be able to convert our undeveloped reserves to developed reserves or that our PUDs will be economically viable or technically feasible to produce.
Further, the SEC rules require that, subject to limited exceptions, PUDs 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 PUDs as we pursue our drilling program. As a result, we may be required to reclassify certain of our PUDs if we do not drill those wells within the required five-year timeframe.
The marketability of our production is dependent upon access to gathering, treating, processing and transportation facilities, which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues could decrease.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of gathering, treating, processing and transportation pipelines, plants and other midstream facilities, which are owned by third parties. Our oil is collected from the wellhead to our tank batteries and then transported by the purchaser by truck or pipeline to a tank farm, another pipeline or a refinery. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point. We do not control these third-party facilities and our access to them may be limited, curtailed or denied. Pipelines, plants, and other
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midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, and curtailments of receipts or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. The third-party facilities may experience unplanned downtime or maintenance for a variety of reasons outside our control and our production could be materially negatively impacted as a result of such outages. Insufficient production from our wells in the properties we do not operate to support the construction of pipeline facilities by third parties or a significant disruption in the availability of our or third-party midstream facilities or other production facilities could adversely impact our ability to deliver to market or produce our natural gas and thereby causing a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement gathering, treating, processing or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. 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 materially and adversely affect our financial condition and results of operations.
We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flows and ability to complete development activities as planned.
Historically, our capital and operating costs have risen during periods of increasing oil and natural gas prices and drilling activity in our areas of operation and other major shale basins across the U.S. These cost increases result from a variety of factors beyond our control, such as increases in the cost of sand and other proppants used in hydraulic fracturing operations, and electricity, steel and other raw materials, including water, that we and our vendors rely upon; increased demand for experienced development crews and oil field equipment and services and materials as drilling activity increases; and increased taxes, which could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and reduce our Distributable Cash from Operations. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than the following increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flows and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.
Our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Difficulties that we face while completing our wells include the ability to:
| • | fracture stimulate the planned number of stages with the planned amount of proppant; |
| • | run tools through the entire length of the wellbore during completion operations; |
| • | run our casing the entire length of the wellbore; |
| • | space wells to maximize economic return; |
| • | land our wellbore in the desired drilling zone; |
| • | stay in the desired drilling zone while drilling horizontally through the formation; and |
| • | successfully clean out the wellbore after completion of the final fracture stimulation stage. |
In addition, certain techniques we utilize may cause irregularities or interruptions in production due to offset wells being shut-in and the time required to drill and complete multiple wells before any such wells begin producing. If our development and production results are less than anticipated, the return on our investment for a particular well or region may not be as attractive as we anticipated, and we could incur material write-downs of our undeveloped acreage and its value could decline in the future.
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We are highly dependent on the services of our senior management and the loss of senior management or technical personnel could adversely affect our operations.
We depend on the services of our senior management and technical personnel. Our management team has significant experience in the oil and gas industry, and specifically in the Powder River Basin. There can be no assurance that we would be able to replace such members of management with comparable talent or that such replacements would integrate well with our existing team. Further, the loss of the services of our senior management could have a material adverse effect on our business, financial condition and results of operations. In particular, the loss of the services of one or more members of our management team could disrupt our operations. We do not maintain, nor do we plan to obtain, “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. Our continued success will depend, in part, on our ability to attract and retain experienced technical personnel, including geologists, engineers and other professionals. Competition for these professionals is strong and will likely intensify as a significant portion of today’s engineers, geologists and other professionals working within the oil and natural gas industry will reach the age of retirement in the coming years. We are likely to continue to experience increased costs to attract and retain these professionals.
Regardless, retirements and other factors may lead to an increased demand for qualified, entry-level technical personnel, increased compensation costs, and additional competition from oil and gas companies attempting to meet their hiring needs. If a shortage of technical personnel materializes, companies in the oil and gas industry may be unable to hire adequate numbers of technical personnel, resulting in disruptions, increased costs of operations, financial difficulties and other adverse effects. These circumstances may become more severe in the future and, as a consequence, cause a material adverse effect on our business.
We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease funds available for servicing our debt obligations and other operating expenses.
We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to acquire decommissioning bonds or to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which, in the case of a decommissioning fund, could decrease monies available to service debt obligations. We note that such reserve funds, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.
Asset retirement obligations for our oil and gas assets and properties are estimates, and actual costs could vary significantly.
We are required to record a liability for the discounted present value of our estimated asset retirement obligations to plug, abandon, and decommission inactive wells and related assets and non-producing oil and gas properties in which we have a working interest. Such asset retirement obligations may include complete structural removal and/or restoration of the land. As of December 31, 2023, we had accrued asset retirement obligations of approximately $2.8 million for our Powder River Basin assets. Although management has used its best efforts to determine future asset retirement obligations, assumptions and estimates can be influenced by many factors beyond management’s control, including, but not limited to, changes in regulatory requirements, which may be more restrictive in the future, changes in costs for abandonment related services and technologies, which could increase or decrease based on supply and demand, and/or extreme weather conditions, such as cyclones, tornadoes, lightning storms, and other extreme weather events, which may cause structural or other damage to oil and natural gas assets and properties. Accordingly, our estimate of future asset retirement obligations could differ materially from actual costs that may be incurred.
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Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to, or control of, sensitive information or to render our data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. In addition, if our third-party vendors do not maintain adequate security measures, do not require their sub-contractors to maintain adequate security measures, do not perform as anticipated and in accordance with contractual requirements, or become targets of cyber-attacks, we may experience a breach of customer data or operational difficulties and increased costs, which could materially and adversely affect our business. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.
We have not experienced, to date, any cybersecurity incidents or had any material business interruptions or material losses from breaches of cybersecurity. However, there is no assurance that we will not suffer any such interruptions or losses in the future. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, phishing, ransomware, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. Although we maintain insurance to protect against losses resulting from certain data protection breaches and cyber-attacks, our coverage for protecting against such risks may not be sufficient.
In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period, and our systems and insurance coverage for protecting against such cybersecurity risks may be costly and may not be sufficient. As cyber-attackers become more sophisticated, we may be required to expend significant additional resources to continue to protect our business or remediate the damage from cyber-attacks. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, and we may be required to bear additional costs and efforts to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. To the extent we face increased regulatory requirements, we may be required to spend additional resources to meet such requirements.
We are subject to a number of privacy and data protection laws, rules and directives (collectively, “data protection laws”) relating to the processing of personal data.
The regulatory environment surrounding data protection laws continues to grow in complexity and scope. We collect, use, share, retain, delete and otherwise process certain personal information and other sensitive personal information in connection with our operations. We are subject to a variety of laws and regulations, including state data breach notification laws, and may become subject to additional pending laws and regulations that govern the collection, use and other processing of such information obtained from individuals, businesses and other third parties. These laws and regulations are inconsistent across jurisdictions and are subject to evolving interpretations. Government officials, regulators, privacy advocates and class action attorneys are increasingly scrutinizing how companies collect, process, use, store, share, transmit and destroy personal data. We must continually monitor the development and adoption of, and commit substantial time and resources to comply with, new and emerging laws and regulations and/or expanded interpretations of existing laws, which may increase the costs and complexity of compliance. These laws and regulations provide disclosure and other
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obligations for businesses that collect personal information, individual rights relating to personal information, collection, use, storage, transmission and other processing requirements, and potential liability expansion.
Any failure, or perceived failure, by us to comply with applicable data protection laws, regulations, policies, industry standards, contractual obligations, or other legal obligations, including at newly acquired companies, could result in proceedings or actions against us by governmental entities or others and expose us to significant damage awards, fines, and other penalties that could materially harm our business reputation. Such litigation and enforcement may require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws.
Loss of our information and computer systems could adversely affect our business.
We are 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 adversely affect our operations, customer service, and competitive position and have a material adverse effect on our business. They may also result in a breach of our contractual obligations or legal duties. Such a breach could expose us to business interruption, lost revenue, ransom payments, remediation costs, liabilities to affected parties, cybersecurity protection costs, lost assets, litigation, regulatory scrutiny and actions, reputational harm, harm to our vendor relationships, or loss of market share.
We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
We maintain insurance against some, but not all, operating risks and losses. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
Our operations are subject to all of the risks associated with drilling for and producing oil and natural gas including the risk of:
| • | environmental hazards, such as releases of pollutants into the environment, including groundwater, surface water, soil and air contamination; |
| • | formations with abnormal or unexpected pressures; |
| • | mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; |
| • | ruptures, fires, explosions or well blowouts; |
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| • | loss of well control or malfunction to or damage to pipelines, processing plants, compression assets, water infrastructure, and related equipment and surrounding properties; |
| • | inadvertent damage from construction, vehicles, farm and utility equipment; |
| • | personal injuries and death; |
| • | natural disasters; and |
| • | terrorist attacks targeting oil and natural gas related facilities and infrastructure. |
Any of these events could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims by government agencies or third parties for:
| • | injury or loss of life; |
| • | damage to or destruction of property, facilities, natural resources and equipment; |
| • | pollution or other environmental damage; |
| • | suspension or interruption of our operations; |
| • | regulatory investigations and penalties; and |
| • | repair and remediation costs. |
We maintain insurance against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable.
Limitations or restrictions on our ability to obtain and dispose of water may have a material adverse effect on our operating results.
Water is an essential component of our operations during the drilling and hydraulic fracturing processes and the production life cycle. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. Disposal of produced water as a result of drilling, hydraulic fracturing, and production is also a critical component of our operations. Access to appropriate, permitted third-party water disposal facilities may be adversely affected due to a number of factors outside of our control. Capacity limitations, permitting issues, air emissions, remediation, and competition for disposal facilities are risks to our water disposal requirements and may adversely affect our business, financial condition, and cash flow.
Our Existing Credit Agreement contains restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
Our Existing Credit Agreement contains a number of significant covenants, including restrictive covenants that will, subject to certain qualifications, restrict, among other things our ability to:
| • | incur certain liens or permit them to exist; |
| • | merge or consolidate with another company; |
| • | incur or guarantee additional debt; |
| • | make certain investments and acquisitions; |
| • | hedge future production or interest rates; |
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| • | make or pay distributions on, or redeem or repurchase, common units, if an event of default exists; |
| • | enter into certain types of transactions with affiliates; |
| • | restrict the transfer, sell or otherwise dispose of assets; and |
| • | engage in certain other transactions without the prior consent of our lenders. |
In addition, our Existing Credit Agreement requires us to comply with customary financial covenants and specified financial ratios, including that we maintain, as of the last day of any fiscal quarter, (i) a current ratio greater than 1.0 to 1.0 (the “Current Ratio Covenant”), (ii) a ratio of total net indebtedness-to-EBITDAX of not greater than 2.75 to 1.00, (iii) a ratio of PDP assets plus or minus the value of future hedge settlements (both discounted at a 10% rate) to net indebtedness of not less than 1.75 to 1.00 and (iv) maintain at least $5,000,000 in liquidity. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.
For the fiscal quarter ended December 31, 2023, we failed to comply with the Current Ratio Covenant, and as a result of such failure, an event of default occurred under the Existing Credit Agreement. Pursuant to the Waiver and Consent to Credit and Guaranty Agreement, dated as of April 11, 2024, the lenders waived such event of default. There is no assurance that we will be able to obtain any future waivers. If we are unable to comply with the Current Ratio Covenant for a future period or other customary financial covenants and specified financial ratios or violate any other provisions of our Existing Credit Agreement that are not cured or waived within specific time periods, our lender may declare our indebtedness thereunder to be immediately due and payable, our ability to make distributions will be inhibited and our lenders’ commitment to make further loans to us may terminate. Any such acceleration of such debt could also result in a cross-acceleration of other future indebtedness which we may incur. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our Existing Credit Agreement are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our Existing Credit Agreement, the lenders could seek to foreclose on our assets or force us to seek bankruptcy protection.
In addition, our Existing Credit Agreement may hinder our ability to effectively execute our hedging strategy. Our Existing Credit Agreement requires the minimum percentage of our production that we can hedge and the duration and structure of those hedges, so we may be required to enter into commodity derivative contracts at inopportune times.
We are currently in the process of negotiating the New Credit Facility with prospective lenders that we anticipate entering into after the completion of this offering. The terms of the New Credit Facility are in the process of being negotiated with prospective lenders based on market conditions. To the extent we successfully negotiate and enter into the New Credit Facility, we cannot ensure that such terms will be the same as or more favorable than the terms described in the Existing Credit Agreement.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our Existing Credit Agreement, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If oil and natural gas prices decline for an extended period of time, we may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional equity or debt capital or
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restructure or refinance indebtedness or seek bankruptcy protection to facilitate a restructuring. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt or preferred equity arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Existing Credit Agreement currently restricts, and the New Credit Facility may restrict, our ability to dispose of assets and our use of the proceeds from such disposition in certain circumstances. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
Any significant reduction in the borrowing base under a replacement facility, such as the New Credit Facility, as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
In the future, if we have a revolving reserve-based loan, including under the New Credit Facility, which we are in the process of negotiating, we may not be able to access adequate funding as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lenders to meet their funding obligations. Declines in commodity prices could result in a determination by the lenders to decrease the borrowing base in the future and, in such a case, we could be required to promptly repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our Existing Credit Agreement or New Credit Facility bear or will bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and could materially impact our business, financial condition and results of operations and distributions.
Our level of indebtedness may increase and reduce our financial flexibility.
Although we do not expect to have significant net indebtedness at the closing of this offering, in the future we may incur significant indebtedness through future debt issuances in order to make acquisitions or to develop our properties or for other general partnership purposes. Such indebtedness could affect our operations in several ways:
| • | a significant portion of our cash flows could be used to service our indebtedness; |
| • | a high level of debt would increase our vulnerability to general adverse economic and industry conditions; |
| • | the covenants contained in the agreements governing our outstanding indebtedness may limit our ability to borrow additional funds, dispose of assets, pay distributions on our Class A Common Units 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 not be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; |
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| • | our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and our industry; |
| • | a high level of debt may make it more likely that a reduction in any future borrowing base following a periodic redetermination could require us to repay a significant portion of our then-outstanding bank borrowings; and |
| • | 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. |
A high level of indebtedness, if incurred in the future, 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 in such event depends on our future performance. General economic conditions, commodity 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 of our common units or a refinancing of our debt include financial market conditions (including any financial crisis), the value of our assets, and our performance at the time we need capital.
We cannot assure you that we will be able to obtain the New Credit Facility to refinance the indebtedness under the Existing Credit Agreement, or that we will be able to refinance the indebtedness we will incur under the New Credit Facility.
There can be no assurance that the New Credit Facility will be obtained on the terms described herein, or at all. In order to obtain the New Credit Facility, which we are in the process of negotiating, we must first obtain commitments from lenders for the New Credit Facility, and agree on final definitive documentation for the New Credit Facility with the lenders. We may not be able to arrange such commitments, or the pricing, size, covenants or other terms of the facility may be less favorable than the New Credit Facility described herein, which could increase our interest costs, reduce our operational or financial flexibility, or reduce our access to liquidity. If we are unable to obtain binding commitments for the New Credit Facility on acceptable terms or at all, the Existing Credit Agreement will remain outstanding. If we enter into the New Credit Facility after the closing of this offering, we will use borrowings under the New Credit Facility and a portion of the net proceeds of this offering to repay in full the obligations under the Existing Credit Agreement (including payment of the applicable prepayment fee) and terminate our Existing Credit Agreement. No assurance can be given that any refinancing or additional financing will be possible when needed or that we will be able to negotiate favorable terms. In addition, our access to capital is affected by prevailing conditions in the financial and capital markets and other factors beyond our control. There can be no assurance that market conditions will be favorable at the times that we require new or additional financing. Further, changes by any rating agency to our credit rating may negatively impact the value and liquidity of both our debt and equity securities, as well as the potential costs associated with refinancing our debt, including the Existing Credit Agreement and, if ultimately agreed, the New Credit Facility. Downgrades in our credit ratings could also affect the terms of any such financing and restrict our ability to obtain additional financing in the future. Failure to obtain the New Credit Facility or to refinance the indebtedness under the Existing Credit Agreement could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Increased attention to ESG matters and conservation measures may adversely impact our business.
Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary environmental, social and governance (“ESG”) disclosures, and consumer demand for alternative forms of energy, may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on the price of our Class A Common Units and access to capital markets. Increasing attention to climate change and
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environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of, or contribution to, the asserted damage, or to other mitigating factors.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters in the future, many of the statements in those voluntary disclosures may be on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation, given the long timelines involved and the lack of an established single approach to identifying and measuring many ESG matters.
In addition, organizations that voluntarily provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets, could lead to increased negative investor sentiment toward us and our industry, and to the diversion of investment to other industries, which could have a negative impact on our access to, and costs of, capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.
We may face various risks associated with the long-term trend toward increased activism against oil and gas exploration and development activities.
Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands, and delay or cancel certain projects, such as the development of oil and gas shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling and hydraulic fracturing in the United States, even in jurisdictions that are among the most stringent in their regulation of the industry. Future activist efforts could result in the following:
| • | Delay or denial of drilling permits. |
| • | Shortening of lease terms and reduction in lease size. |
| • | Restrictions on installation or operation of production, gathering or processing facilities. |
| • | Restrictions on installation and operation of transmission pipelines. |
| • | Restrictions on the use of certain operating practices, such as hydraulic fracturing, or disposal of related waste materials, such as hydraulic fracking fluids and production. |
| • | Increased severance and/or other taxes. |
| • | Cyber-attacks. |
| • | Legal challenges or lawsuits. |
| • | Negative publicity about our business or the oil and gas industry in general. |
| • | Increased costs of doing business. |
| • | Reduction in demand for our products. |
| • | Other adverse effects on our ability to develop our properties and expand production. |
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We may incur significant costs associated with responding to these initiatives. Complying with any resulting additional legal or regulatory requirements that are substantial, could have a material adverse effect on our business, financial condition, cash flow, results of operations, and ability to pay distributions on our Class A Common Units.
Prolonged negative investor sentiment toward upstream natural gas and oil-focused companies could limit our access to capital funding, which would constrain liquidity.
Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector, versus other sectors, have led to lower natural gas and oil representation in certain key equity market indices. Some investors, including certain pension funds, private equity funds, university endowments, and family foundations, have stated policies to reduce or eliminate their investments in the natural gas and oil sector based on social and environmental considerations. Certain other stakeholders have pressured commercial and investment banks to stop funding hydrocarbon extraction, transportation, or refining. If this negative sentiment continues or worsens, it may reduce the availability of capital funding for potential development projects, each of which could have a material adverse effect our financial condition, results of operations, cash flows, and ability to pay distributions on our Class A Common Units.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing availability of, and consumer and industrial/commercial demand for alternatives to oil and natural gas (e.g., alternative energy sources), and products manufactured with, or powered by, non-oil and gas sources (e.g., electric vehicles and renewable residential and commercial power supplies), and technological advances in fuel economy and energy generation, transmission, storage and consumption of energy (e.g., wind, solar and hydrogen power, smart grid technology and battery technology), 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 flow.
In addition, our business could be impacted by governmental initiatives to incentivize the conservation of energy or the use of alternative energy sources, such as with the previously mentioned, “Long-Term Strategy for the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” or with the U.S. DOT’s recent issue of more stringent fuel economy standards. These initiatives, or similar state or federal initiatives to reduce energy consumption or incentivize a shift away from fossil fuels, could reduce demand for hydrocarbons and have a material adverse effect on our earnings, cash flows, and financial condition.
Risks Related to Environmental and Regulatory Matters
We must adhere to stringent requirements by multiple governing agencies—all of which have the potential to adversely impact the cost and feasibility of our endeavors, and/or expose us to significant risk of liability.
Our operations are subject to a myriad of federal, state, and local laws and regulations which govern occupational health and safety, seek to measure and limit the discharge of materials, and aim to safeguard and protect natural resources and the environment (including threatened and endangered species). These laws and regulations may impose numerous obligations applicable to our operations, including but not limited to: the approval of permits before commencement of drilling and other regulated activities; the restriction of types, quantities and concentrations of materials that may be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, and other ecologically or seismically sensitive areas; the application of specific health and safety criteria addressing worker protection; the imposition of substantial liabilities for emissions resulting from our operations; and the assumption of costs related to land reclamation and restoration.
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Governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state counterparts, have the power to enforce compliance with these laws and regulations, and with the restrictions and requirements laid out in the permits they issue. Such enforcement often results in complicated and costly measures or corrective action. Further, failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders to limit or prohibit some or all of our operations. Additionally, we may experience delays in obtaining, or be unable to obtain, required permits, resulting in delays or interruptions to our operations and specific projects, thereby limiting our growth and revenue.
Owing to the handling of petroleum hydrocarbons and other potentially harmful substances as well as air emissions, wastewater and solid waste generation related to our operations, and historical operations and waste disposal practices that took place at our leased and owned properties, we carry an inherent risk of incurring significant environmental costs and liabilities. Spills, air emissions or other releases of regulated substances could expose us to material losses, expenditures, and liabilities. Under certain applicable environmental laws and regulations, we could also be subject to strict joint and several liability for the removal or remediation of contamination, regardless of whether we were responsible for the release or contamination, and even if our operations met the previous industry standards at the time they were conducted. Furthermore, we may not be able to recover some, or any, of these costs from insurance.
The trend in environmental regulation has long been towards more stringent requirements. Changes that result in more costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, and disposal or cleanup requirements, could require us to make significant expenditures to attain and maintain compliance, and may otherwise have a material adverse effect on the results of our operations, competitive position, or financial condition. Compliance with these and other increasingly stringent environmental regulations at the federal and state levels could also delay or prohibit our ability to obtain permits for operations, or require us to install additional pollution control equipment, the costs of which could be significant. Furthermore, proposed regulations may require retrofitting of existing equipment to meet current emission control requirements. See “Business and Properties—Operations,” for a more comprehensive description of the laws and regulations that affect us.
Should we fail to comply with all applicable agency administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines arising from allegations of market manipulation.
Several federal agencies have statutory authority to regulate market manipulation in the crude oil and natural gas industries, including the Federal Energy Regulatory Commission (“FERC”), the Federal Trade Commission (“FTC”), and the Commodity Futures Trading Commission (“CFTC”). FERC, under the Natural Gas Act, enforces transparency and anti-market manipulation rules related to the natural gas markets. The FTC has regulations to prohibit market manipulation in the petroleum industry, and the CFTC regulates market manipulation with respect to derivatives, swaps and futures contracts related to crude oil and natural gas purchases and sales. Each regulator also has civil penalty enforcement authority of over $1 million per violation per day.
Our operations are subject to a series of risks arising from the threat of climate change, which could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for the oil and natural gas we produce.
Following the U.S. Supreme Court finding that greenhouse gas (“GHG”) emissions constitute a pollutant under the Clean Air Act (“CAA”), the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and, together with the Department of Transportation (“DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, on August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”), which includes billions of dollars in incentives
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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, in March 2024, the EPA finalized ambitious rules to reduce harmful air pollutant emissions, including GHGs, from light-, medium-, and heavy-duty vehicles beginning in model year 2027. These rules and incentives 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.
The IRA also 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 applicable waste emissions threshold from sources required to report their GHG emissions to the EPA, including those sources in the oil and gas sector. 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 thresholds established in the IRA. On January 26, 2024, the EPA published a proposed rule to implement the methane emissions charge. The methane emissions charge could increase our operating costs, which could adversely impact our business, financial condition and cash flows.
The federal government has also increased regulation of methane from oil and gas facilities in recent years. For example, in 2016, the EPA issued regulations under its New Source Performance Standards (“NSPS”, Subpart OOOOa) requiring operators to reduce methane and VOC emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants, and natural gas transmission compressor stations. On March 8, 2024, the EPA finalized new rules under NSPS OOOOb and OOOOc to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector, though the Texas Railroad Commission and Texas Commission on Environmental Quality have petitioned to challenge the rule in court. Though the final outcome of the NSPS is uncertain, the rule, as written, establishes standards of performance for sources that commence construction, modification or reconstruction after March 8, 2024, and establishes emissions guidelines that will subsequently inform state plans to establish standards for existing sources. If implemented as currently drafted, these increasingly stringent methane and VOC requirements on new facilities, or the application of new requirements to existing facilities, could result in additional restrictions on our operations and increase compliance costs, which could be significant. Given the long-term trend toward increasing regulation, we fully expect there will be additional future federal GHG regulations of the oil and gas industry.
Additionally, various states, and groups of states, have adopted or are considering adopting, legislation, regulations or other regulatory initiatives that are focused on GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.
Internationally, 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, which went into effect on November 4, 2016, requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. On April 21, 2021, President Biden announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 (relative to 2020 levels), including “all feasible reductions” in the energy sector. President Biden also agreed that same month to cooperate with Chinese leader Xi Jinping on accelerating progress toward the adoption of clean energy. Most recently, at the 28th Conference of the Parties in the United Arab Emirates, world leaders agreed to transition away from fossil fuels in a just, orderly and equitable manner and to triple renewables and double energy efficiency globally by 2030. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’
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commitments under the Paris Agreement, COP26, or other international conventions, cannot be predicted at this time. However, to the extent these developments result in new restrictions on oil and gas operations, increase operational costs, or otherwise reduce the demand for oil and gas, they could have a material adverse effect on our business.
Litigation risks are also increasing, as several entities have sought to bring suit against oil and natural gas companies in state or federal courts, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change. Suits have also been brought against such companies under shareholder and consumer protection laws, alleging that companies have been aware of the adverse effects of climate change, but failed to adequately disclose those impacts.
Fossil fuel producers face increasing financial risks as investors currently invested in fossil fuel energy companies may elect to shift some or all of their investments into other sectors. Institutional lenders who provide financing to fossil fuel energy companies have become more attentive to sustainable lending practices, and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the Federal Reserve has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in, and financing for, fossil fuel energy companies, could result in the restriction, delay or cancellation of drilling programs or development and production activities.
Additionally, the SEC recently adopted, and then paused, rules relating to the disclosure of a range of climate-related risks. If implemented, the rules are expected to impose several new disclosure obligations, including: (i) disclosure on an annual basis of a registrant’s Scope 1 and Scope 2 GHG emissions; (ii) third-party independent attestation of the same for accelerated and large accelerated filers; (iii) disclosure on how a general partner’s board of directors and underlying management oversee climate-related risks and certain climate-related governance items; (iv) disclosure of information related to a registrant’s publicly announced climate-related targets, goals and/or transition plans; and (v) disclosure of whether and how climate-related events and transition activities impact line items above a threshold amount on a registrant’s consolidated financial statements, including the impact of the financial estimates and the assumptions used. While we, as an emerging growth company, would not be required to report GHG emissions (including Scope 1 and Scope 2 emissions) and will be subject to a longer phase-in for other climate-related disclosure requirements (starting in the fiscal year beginning in 2027), we are currently assessing this rule and cannot predict the costs of implementation or any potential adverse impacts resulting from the rule, should it be adopted as proposed. We expect, however, these costs to be substantial. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders to restrict or seek more stringent conditions with respect to their investments in certain carbon-intensive sectors.
The adoption and implementation of new or more stringent international, federal, regional or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector, or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions, could result in increased costs of compliance or costs of consumption, thereby reducing demand for oil and natural gas. Additionally, political, financial, and litigation risks may result in our restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these
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developments could have a material adverse effect on our business, financial condition, and the results of our operations.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of unconventional oil and natural gas wells, adversely affecting our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand, or alternative proppant and chemicals under pressure, into targeted geological formations to fracture the surrounding rock and stimulate production.
Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, 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. 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.
Additionally, the EPA published final CAA regulations in 2012 and, more recently, in June 2016 and March 2024, governing CAA performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing and leak detection, and further, permitting an effluent limitation guideline that prohibits the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.
Similarly, in 2015, the Bureau of Land Management (“BLM”), finalized rules establishing stringent standards relating to hydraulic fracturing on federal and Indian lands, including well casing and wastewater storage requirements and an obligation for exploration and production operators to disclose what chemicals they are using in fracturing activities. In December 2017, the BLM repealed the 2015 hydraulic fracturing rule. Rescission of the rule was challenged by several environmental groups and states in the United States District Court for the Northern District of California, which, in a March 2020 decision, upheld the BLM’s recission.
Additionally, from time to time, legislation has been introduced, but not enacted in Congress, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, states have continued to regulate hydraulic fracturing.
In the event that new federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we may incur additional costs to comply with such requirements when horizontally completing wells, which could be significant in nature, and could also become subject to additional permitting requirements resulting in added delays or curtailment of the pursuit of exploration, development, or production activities, thereby having a material adverse effect on our business and results of operations. (See “Business and Properties—Operations,” for a further description of the laws and regulations that affect us.)
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Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling and completion activities in areas where we operate.
Oil and natural gas operations in our areas of exploration and development may be adversely affected by seasonal or permanent restrictions on drilling and completion activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, equipment, services, supplies, and qualified personnel, which may lead to periodic shortages when drilling or completion is allowed. These constraints, and the resulting shortages or high costs, could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling and completing in certain areas or require the implementation of expensive mitigation measures. Additionally, 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, causing a material adverse impact on our ability to develop and produce our reserves.
Risks Inherent in an Investment in Us
Our general partner and its affiliates own a controlling interest in us and may have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.
Our general partner will have control over all decisions related to our operations. Upon consummation of this offering, our management team and members of our Board, some of whom are also affiliated with Yorktown (collectively, the “Sponsors”) will own all of the membership interests in our general partner. Upon the completion of this offering, the Sponsors will own an aggregate of approximately % of our outstanding Class A Common Units (or % of our outstanding Class A Common Units on an as-converted basis as a result of their ownership of Class B Common Units). Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the executive officers and directors of our general partner also have a duty to manage our general partner in a manner that is not adverse to the best interests of its owners. As a result of these relationships, conflicts of interest may arise in the future between the Sponsors and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following:
| • | our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty; |
| • | neither our partnership agreement nor any other agreement requires the Sponsors or their respective affiliates (other than our general partner) to pursue a business strategy that favors us; |
| • | the Sponsors and their affiliates are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us; |
| • | our general partner determines the amount and timing of our development operations and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders; |
| • | except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; |
| • | our general partner determines which costs incurred by it and its affiliates are reimbursable by us; |
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| • | our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; |
| • | our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us; |
| • | our general partner may exercise its limited right to call and purchase Class A Common Units if it and its affiliates own more than 80% of the then outstanding Class A Common Units; |
| • | our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and |
| • | our general partner decides whether to retain separate counsel, accountants or others to perform services for us. Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Duties.” |
As a result of such potential conflicts of interests and the limited duties they owe to us, our general partner and its affiliates may favor their own interests to the detriment of us and our unitholders.
The conversion of Class B Common Units into Class A Common Units could lead to selling pressure on the Class A Common Unit price.
The conversion of Class B Common Units into publicly-traded Class A Common Units will provide liquidity to the Class B Common Unitholders, some of whom may elect to sell the Class A Common Units they receive. In addition, Yorktown may elect to make distributions of Class A Common Units to the limited partners in the Yorktown partnerships, some of whom may also elect to sell the Class A Common Units they receive. Future sales of Class A Common Units received in exchange for Class B Common Units could put downward pressure on the market price of the Class A Common Units. While the Class B Common Units are designed to be convertible only upon an excess Distributable Cash from Operations coverage test, which we intend will protect the existing Class A Common Unitholder distribution, there can be no assurance that the Class A Common Units that are ultimately issued upon conversion will not be dilutive.
Our partnership agreement does not restrict our Sponsors and their respective affiliates from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner are not prohibited from owning projects or engaging in businesses that compete directly or indirectly with us. Similarly, our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and our Sponsors do not have any obligation to present business opportunities to us.
In addition, certain of our officers and directors may in the future hold similar positions with investment partnerships or other private entities that are in the business of identifying and acquiring mineral and royalty interests. In such capacities, these individuals would likely devote significant time to such other businesses and would be compensated by such other businesses for the services rendered to them. The positions of these directors and officers may give rise to duties that are in conflict with duties owed to us. In addition, these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these potential future affiliations, they may have duties to present potential business opportunities to those entities prior to presenting them to us, which
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could cause additional conflicts of interest. Our Sponsors and their respective affiliates will be under no obligation to make any acquisition opportunities available to us, except as provided for under the contribution agreement. See “Conflicts of Interest and Duties.”
Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors, our Sponsors and their respective affiliates. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and holders of our Class A Common Units.
Our partnership agreement requires that we distribute all of our Available Cash, if any, which could limit our ability to grow our reserves and production and make acquisitions.
Our partnership agreement requires that we distribute all of our Available Cash, if any, each quarter. As a result, we expect to rely primarily upon our cash reserves, cash from operations and external financing sources, including the issuance of additional Class A Common Units and other partnership interests, to fund future development drilling, completion activities and acquisitions of acreage and/or producing properties and finance our growth. To the extent we are unable to finance growth with our cash reserves and external sources of capital, the requirement in our partnership agreement to distribute all of our Available Cash may impair our ability to grow.
A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:
| • | general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds; |
| • | conditions in the oil and gas industry; |
| • | the market price of, and demand for, our Class A Common Units; |
| • | our results of operations and financial condition; and |
| • | prices for oil and natural gas. |
In addition, because we distribute all of our Available Cash, our growth may not be as fast as that of businesses that reinvest their Available Cash to expand ongoing operations. To the extent we issue additional Class A Common Units in connection with any acquisitions or expansion capital expenditures, or upon the conversion of the Class B Common Units to Class A Common Units, the payment of distributions on those additional Class A Common Units may increase the risk that we will be unable to maintain or increase our per Class A Common Unit distribution level. There are no limitations in our partnership agreement or our Existing Credit Agreement on our ability to issue additional Class A Common Units, including units ranking senior to the Class A Common Units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the Available Cash that we have to distribute to our Class A Common Unitholders.
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Our partnership agreement replaces our general partner’s fiduciary duties to our unitholders with contractual standards governing its duties, and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with different contractual standards. For example, our partnership agreement provides that:
| • | whenever our general partner (acting in its capacity as our general partner), the Board or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was not adverse to our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or equitable principle; |
| • | our general partner may make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include: |
| • | how to allocate corporate opportunities among us and its other affiliates; |
| • | whether to exercise its limited call right; |
| • | whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board or our unitholders; |
| • | how to exercise its voting rights with respect to the units it owns; |
| • | whether to sell or otherwise dispose of any units or other partnership interests it owns; and |
| • | whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement. |
| • | our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith; |
| • | our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
| • | our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is: |
| (1) | approved by the conflicts committee of the Board, if any; |
| (2) | approved by the vote of a majority of the outstanding Class A Common Units and Class B Common Units, voting together as a single class (excluding any Class A Common Units and Class B Common Units owned by the general partner and its affiliates); |
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| (3) | determined by the Board to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| (4) | determined by the Board to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by the vote described in the second sub-bullet point above and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub-bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
All limited partners are bound by the provisions in the partnership agreement, including the provisions discussed above.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. In addition, as with other yield-oriented securities, our Class A Common Unit price is impacted by the level of our cash distributions to our Class A Common Unitholders and implied distribution yield. This implied distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our Class A Common Units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt. See “Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.”
Class A Common Units held by persons who our general partner determines are not eligible holders will be subject to redemption.
To comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on U.S. federal lands, we have adopted certain requirements regarding those investors who may own our Class A Common Units. As used herein, an “Eligible Holder” means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:
| • | a citizen of the United States; |
| • | a corporation organized under the laws of the United States or of any state thereof; |
| • | a public body, including a municipality; or |
| • | an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. |
Onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Class A Common Unitholders who are not persons or entities who meet the requirements to be
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an Eligible Holder run the risk of having their Class A Common Units redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of Our Securities—Transfer of Class A Common Units.”
Our unitholders have limited voting rights and are not entitled to elect our general partner or the Board, which could reduce the price at which our Class A Common Units will trade.
Unlike the holders of common stock in a corporation, unitholders (including Class A Common Unitholders and Class B Common Unitholders) have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The Board, including the independent directors, is chosen entirely by the Sponsors, as a result of their ownership of our general partner, and not by our unitholders. Please read “Management—Board of Directors” and “Certain Relationships and Related Party Transactions.” Unlike publicly-traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which our Class A Common Units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our general partner will have control over all decisions related to our operations. Since, upon consummation of this offering, our general partner will continue to be owned by the Sponsors, who collectively with Yorktown and affiliates of Yorktown, will own and control the voting of an aggregate of approximately % of our outstanding Class A Common Units and Class B Common Units, voting together as a single class, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding Class A Common Units and Class B Common Units, voting together as a single class (including Class A Common Units and Class B Common Units held by Yorktown and its affiliates). Assuming we do not issue any additional Class A Common Units and Class B Common Units, and Yorktown does not transfer any of its Class A Common Units and Class B Common Units, Yorktown will have the ability to amend our partnership agreement, including our policy to distribute all of our Available Cash to our Class A Common Unitholders without the approval of any other unitholder. Furthermore, the goals and objectives of Yorktown and its affiliates that hold our Class A Common Units and Class B Common Units relating to us may not be consistent with those of a majority of the other unitholders.
Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent (other than for cause).
The public unitholders will be unable initially to remove our general partner without cause or without its consent because affiliates of our general partner will own sufficient Class A Common Units and Class B Common Units upon completion of this offering to be able to prevent the removal of our general partner. Our general partner may not be removed except for cause by a vote of the holders of at least 66 2/3% of the outstanding Class A Common Units and Class B Common Units, including any Class A Common Units and Class B Common Units owned by our general partner, its members and their respective affiliates, voting together as a single class, and we receive an opinion of counsel regarding limited liability matters. Immediately upon consummation of this offering, our Sponsors and Yorktown will own an aggregate of approximately % of our Class A Common Units and Class B Common Units, voting together as a single class, which will enable those holders, collectively, to prevent the removal of our general partner.
Control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the Sponsors, who own our
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general partner, from transferring all or a portion of their ownership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and thereby influence the decisions made by the Board and officers.
We may issue an unlimited number of additional units, including units that are senior to the Class A Common Units, without unitholder approval, which may dilute your ownership interest in us.
Our partnership agreement does not limit the number of additional Class A Common Units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the Class A Common Units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
| • | our unitholders’ proportionate ownership interest in us will decrease; |
| • | the amount of distributions on each unit may decrease; |
| • | the ratio of taxable income to distributions may increase; |
| • | the relative voting strength of each previously outstanding unit may be diminished; and |
| • | the market price of our Class A Common Units may decline. |
We cannot predict the size of future issuances of our Class A Common Units or securities convertible into Class A Common Units or the effect, if any, that future issuances and sales of our Class A Common Units will have on the market price of our Class A Common Units or the distribution amount payable with respect to our Class A Common Units. Sales of substantial amounts of our Class A Common Units (including Class A Common Units issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Units or the distribution amount payable with respect to our Class A Common Units. In addition, the issuance of additional Class A Common Units will result in dilution to the interests of the Class A Common Unitholders.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group owning 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the Board, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.
Once our Class A Common Units are publicly traded, the Existing Owners may sell their Class A Common Units in the public markets, which sales could have an adverse impact on the trading price of the Class A Common Units.
After the sale of the Class A Common Units offered hereby, the Existing Owners (including investment partnerships managed by Yorktown) will own Class A Common Units, or approximately % of our limited partner interests. Once our Class A Common Units are publicly traded, the sale of Class A Common Units by the Existing Owners in the public markets could have an adverse impact on the price of the Class A Common Units or on any trading market that may develop.
Our general partner has a limited call right that may require you to sell your Class A Common Units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the then outstanding Class A Common Units, our general partner will have the right, but not the obligation, which it may assign to any of its
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affiliates or to us, to acquire all, but not less than all, of the Class A Common Units held by unaffiliated persons at a price that is not less than the greater of their then-current market price, as calculated pursuant to the terms of our partnership agreement, and the highest price paid by our general partner or any of its affiliates for Class A Common Units during the 90 day period preceding the date that our general partner notifies the Class A Common Unitholders of its notice of election to exercise the call right. As a result, you may be required to sell your Class A Common Units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your Class A Common Units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the Class A Common Units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional Class A Common Units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the Class A Common Units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. At the closing of this offering, affiliates of our general partner will own approximately % of our Class A Common Units (or % assuming conversion of all of the Class B Common Units held by our general partner, its members and their respective affiliates as of the date of this prospectus into Class A Common Units). For additional information about this call right, please read “The Partnership Agreement—Limited Call Right.”
Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which may limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.
Our partnership agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. This provision would not apply to claims brought to enforce a duty or liability created by the Exchange Act, the Securities Act or any other claim for which the federal courts have exclusive jurisdiction. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of limited partnership inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations. Our partnership agreement also provides that each limited partner waives the right to trial by jury in any such claim, suit, action or proceeding, including any claim under the U.S. federal securities laws, to the fullest extent permitted by applicable law. If a lawsuit is brought against us under our partnership agreement, it may be heard only by a judge or justice of the applicable trial court, which would be conducted according to different civil procedures and may result in different outcomes than a trial by jury would have, including results that could be less favorable to the plaintiffs in any such action. No unitholder can waive compliance with respect to the Partnership’s or such unitholder’s compliance with U.S. federal securities laws and the rules and regulations promulgated thereunder. If the Partnership or one of our unitholders opposed a jury trial demand based on the waiver, the applicable court would determine whether the waiver was enforceable based on the facts and circumstances of that case in accordance with applicable state and federal laws. To our knowledge, the enforceability of a contractual pre-dispute jury trial waiver in connection with claims arising under the U.S. federal securities laws has not been finally adjudicated by the United States Supreme Court. However, we believe that a contractual predispute jury trial waiver provision is generally enforceable, including under the laws of the State of Delaware, which govern our
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partnership agreement. By purchasing a Class A Common Unit, a limited partner is irrevocably consenting to these limitations, provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. For additional information about the exclusive forum provision of our partnership agreement, please read “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.”
The NYSE American does not require a publicly-traded partnership like us to comply, and we do not intend to comply, with certain of its governance requirements generally applicable to corporations.
We intend to apply to list our Class A Common Units on the NYSE American. Because we will be a publicly-traded partnership, the NYSE American will not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE American’s corporate governance requirements. Please read “Management—Management of Peak Resources LP.”
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:
| • | a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
| • | a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
Please read “The Partnership Agreement—Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.
Our unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable both for the obligations of the transferor to make contributions to us that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement.
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Our Class A Common Unitholders may have limited liquidity for their Class A Common Units, respectively, a trading market may not develop for the Class A Common Units and our Class A Common Unitholders may not be able to resell their Class A Common Units, respectively, at the initial public offering price.
Prior to this offering, there has been no public market for the Class A Common Units. After this offering, there will be publicly-traded Class A Common Units, or Class A Common Units if the underwriters exercise their option to purchase additional Class A Common Units in full. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our Class A Common Unitholders may not be able to resell their Class A Common Units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the Class A Common Units and limit the number of investors who are able to buy the Class A Common Units.
If our Class A Common Units price declines after the initial public offering, our Class A Common could lose a significant part of their investment.
The initial public offering price for the Class A Common Units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the Class A Common Units that will prevail in the trading market. The market price of our Class A Common Units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
| • | changes in commodity prices; |
| • | changes in securities analysts’ recommendations and their estimates of our financial performance; |
| • | public reaction to our press releases, announcements and filings with the SEC; |
| • | fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies; |
| • | changes in market valuations of similar companies; |
| • | departures of key personnel; |
| • | commencement of or involvement in litigation; |
| • | variations in our quarterly results of operations or those of other oil and natural gas companies; |
| • | variations in the amount of our quarterly cash distributions to our unitholders; |
| • | changes in tax law; |
| • | future issuances and sales of our Class A Common Units; and |
| • | changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry. |
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our Class A Common Units.
For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation.
The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth
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company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.
Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our Class A Common Units less attractive to investors.
We intend to take advantage of all of the reduced reporting requirements and exemptions available to emerging growth companies under the JOBS Act, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.
Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. Under the JOBS Act, emerging growth companies may also delay adopting new or revised accounting standards until such time as those standards apply to private companies. We cannot predict if investors will find our Class A Common Units less attractive because we will rely on these exemptions. If some investors find our Class A Common Units less attractive as a result, there may be a less active trading market for our Class A Common Units and our Class A Common Unit price may be more volatile.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A Common Units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A Common Units.
We will incur increased costs as a result of being a publicly-traded partnership, which may reduce the amount of cash we have available for distributions to our Class A Common Unitholders and our ability to attract and retain qualified persons to serve on the Board of our general partner or as executive officers.
We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the exchange where our units will be listed, require publicly traded entities to adopt various corporate governance practices that will further increase our costs.
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Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time- consuming and costly. For example, as a result of becoming a publicly traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our Class A Common Unitholders will be affected by the costs associated with being a public company.
We also expect to incur additional expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the Board or as executive officers.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A Common Units or if our operating results do not meet their expectations, Class A Common Unit price could decline.
The trading market for our Class A Common Units 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 visibility in the financial markets, which in turn could cause our unit price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A Common Units or if our operating results do not meet their expectations, our unit price could decline.
Tax Risks to Purchasers of Class A Common Units in this Offering
In addition to reading the following risk factors, prospective purchasers should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our Class A Common Units.
We are treated as a corporation for U.S. federal income tax purposes, and our distributions to our Class A Common Unitholders may be substantially reduced.
We are a Delaware limited partnership and have elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are subject to tax as a corporation at the corporate tax rate. Because an entity-level tax is imposed on us due to our status as a corporation for U.S. federal income tax purposes, our distributable cash flow may be substantially reduced by our tax liabilities.
Distributions to Class A Common Unitholders may be taxable as dividends.
Because we are treated as a corporation for U.S. federal income tax purposes, if we make distributions to our Class A Common Unitholders from current or accumulated earnings and profits as computed for U.S. federal income tax purposes, such distributions will be treated as distributions on corporate stock for U.S. federal income tax purposes, and generally be taxable to our Class A Common Unitholders as ordinary dividend income for U.S. federal income tax purposes (to the extent of our current and accumulated earnings and profits). Such dividend distributions paid to non-corporate U.S. unitholders will be subject to U.S. federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. Any portion of our distributions to Class A Common Unitholders that exceeds our current and accumulated earnings and profits as computed for U.S. federal income tax purposes will constitute a non-taxable return of capital distribution to the extent of a Class A Common Unitholder’s basis in its Class A Common Units and thereafter as gain on the sale or exchange of such units.
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U.S. tax legislation and regulations may change over time, and such changes may adversely affect our business, financial condition, results of operations, 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, such as eliminating the immediate deduction for intangible drilling and development costs. No accurate prediction can be made as to whether any such legislative changes or similar or other tax 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.
In addition, legislation may be proposed with respect to the enactment of a tax levied on the carbon content of fuels based on the GHG emissions associated with such fuels. A carbon tax, whether imposed on producers or consumers, would generally increase the prices for crude oil and natural gas. Such price increases may, in turn, reduce demand for crude oil and natural gas and materially and adversely affect our cash flows, results of operations and financial condition.
In August 2022, President Biden signed into law the IRA, which, among other changes, imposes a 15% corporate alternative minimum tax (the “CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted financial statement net income). We do not believe we will be subject to the CAMT; however, to the extent we are subject to the CAMT, our cash obligations for U.S. federal income taxes could be accelerated. The U.S. Treasury Department, the Internal Revenue Service and other standard-setting bodies are expected to continue to issue guidance on how the CAMT and other provisions of the IRA will be applied or otherwise administered which may differ from our interpretations.
We are unable to predict the timing, scope and effect of any proposed or enacted tax law changes, but any such changes (if enacted) could adversely affect our business, financial condition, results of operations, and cash flows.
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We expect the net proceeds from this offering to be approximately $ million ($ million if the underwriters exercise their option in full to purchase additional Class A Common Units), based upon the assumed initial public offering price of $ per Class A Common Unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and estimated expenses and the structuring fee. We expect that $ million of the net proceeds will be used to fund capital expenditures by the Company’s subsidiaries and that approximately $ of the net proceeds will be used to pay bonuses to certain of our executives related to the consummation of this offering. We expect that $ million of the net proceeds will remain at the Partnership initially designated as a reserve for general partnership purposes, including in order to pay distributions on our Class A Common Units if needed.
We are currently negotiating the New Credit Facility with prospective lenders, and if we enter into the New Credit Facility after the closing of this offering, we will use borrowings under the New Credit Facility and $ million of the net proceeds of this offering to repay in full (including payment of the applicable prepayment fee) and terminate our Existing Credit Agreement. See “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction—Expected Refinancing Transactions” for additional information.
As of June 30, 2024, we had approximately $57.35 million of outstanding borrowings under the Existing Credit Facility, which has a maturity date of January 31, 2027. Borrowings outstanding under the Existing Credit Agreement are initially Term SOFR Loans (as defined in the Existing Credit Agreement), which bear interest at a rate equal to the sum of (i) the Term SOFR Rate for a three-month interest period, plus 0.15% (“Adjusted Term SOFR Rate”); and (ii) 8.00% per annum. Borrowings outstanding under the Existing Credit Facility bore interest at a weighted average rate of 13.5% as of June 30, 2024. The outstanding borrowings under our Existing Credit Facility were incurred to repay in full the Prior Credit Facility (as hereinafter defined) and the NPA (as hereinafter defined), as well as the related debt issuance costs. The remaining outstanding borrowings under the Existing Credit Facility have been incurred to fund Peak E&P’s capital expenditures.
We have granted the underwriters a 30-day option to purchase up to an aggregate of additional Class A Common Units to cover over-allotments of Class A Common Units. To the extent the underwriters’ option to purchase additional Class A Common Units is exercised, we may use the proceeds from the sale of these additional shares to increase capital expenditures or reduce debt.
A $1.00 increase (decrease) in the assumed initial public offering price of $ per Class A Common Unit (the midpoint of the price range set forth on the cover of this prospectus) would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions, estimated offering expenses and the structuring fee, to increase (decrease), respectively, by approximately $ million, assuming the number of Class A Common Units offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase due to a higher initial public offering price, we may use the additional net proceeds to increase capital expenditures or reduce debt. If the proceeds decrease due to a lower initial public offering price, we would reduce by a corresponding amount the net proceeds to be used to fund our capital expenditure program.
The sources and uses of our proceeds may differ from those set forth above. The foregoing represents our current intentions with respect to the use and allocation of the net proceeds of this offering based upon our present plans and business condition, but our management will have significant flexibility and discretion in applying the net proceeds. The occurrence of unforeseen events or changed business conditions could result in application of the net proceeds of this offering in a manner other than as described in this prospectus.
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The following table sets forth as of June 30, 2024:
| • | Our predecessor’s combined historical capitalization on an actual basis; and |
| • | Our predecessor’s combined historical capitalization as adjusted to give effect to (i) the transactions described under “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction” and (ii) this offering and the application of the net proceeds therefrom as set forth under “Use of Proceeds.” |
The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with, and is qualified in its entirety by reference to, “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and pro forma financial statements and related notes appearing elsewhere in this prospectus. For a description of the pro forma adjustments, please read our unaudited pro forma condensed combined financial statements.
| As of June 30, 2024 | ||||||||
| Predecessor Combined Historical | As Adjusted | |||||||
Cash and Cash Equivalents | $ | 9,170 | ||||||
Long-Term Debt, including Current Portion: | ||||||||
Existing Credit Agreement(1) | $ | 57,350 | ||||||
New Credit Facility(2) | — | |||||||
Partners’ Capital/Net Equity: | ||||||||
Class A Common Units held by the public | $ | — | ||||||
Class A Common Units held by Existing Owners | — | |||||||
Class B Common Units held by Existing Owners | — | |||||||
Preferred Equity Held by Existing Owners | $ | 95,886 | ||||||
Common Equity Held by Existing Owners | $ | 24,545 | ||||||
Total Equity Held by Existing Owners | $ | 120,431 | ||||||
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Total Capitalization | $ | 177,781 | ||||||
| (1) | Including current portion as of June 30, 2024, Peak E&P had approximately $57.35 million of outstanding borrowings under the Existing Credit Agreement. For more information on the Existing Credit Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements—Existing Credit Agreement.” |
| (2) | We are currently negotiating the New Credit Facility with prospective lenders, and if we enter into the New Credit Facility after the closing of this offering, we will use borrowings under the New Credit Facility and a portion of the net proceeds of this offering to repay in full the obligations under the Existing Credit Agreement (including payment of the applicable prepayment fee) and terminate our Existing Credit Agreement. |
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Dilution is the amount by which the offering price paid by the purchasers of Class A Common Units sold in this offering will exceed the pro forma net tangible book value per Class A Common Unit after this offering. Pro forma net tangible book value is our total tangible assets less total liabilities. Purchasers of the Class A Common Units in this offering will experience immediate and substantial dilution in the pro forma net tangible book value per Class A Common Unit for accounting purposes. Our pro forma net tangible book value as of June 30, 2024, after giving effect to the transactions described under “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction,” was $ million, or $ per Class A Common Unit.
Assuming an initial public offering price of $ per Class A Common Unit (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving further effect to the sale of the Class A Common Units in this offering and assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions, estimated offering expenses and the structuring fee), our adjusted pro forma net tangible book value as of June 30, 2024 would have been approximately $ million, or $ per Class A Common Unit. This represents an immediate increase in the pro forma net tangible book value of $ per Class A Common Unit to the Existing Owners of Class A Common Units and immediate dilution to new investors purchasing Class A Common Units in this offering of $ per Class A Common Unit. The following table illustrates the per Class A Common Unit dilution to new investors purchasing Units in this offering:
Assumed initial public offering price per Class A Common Unit | $ | |||||||
Pro forma net tangible book value per Class A Common Unit before this offering(1) | $ | |||||||
Increase in pro forma net tangible book value per Class A Common Unit attributable to purchasers in the offering | ||||||||
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Less: Pro forma net tangible book value per Class A Common Unit after this offering(2) | ||||||||
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Immediate dilution in pro forma net tangible net book value per Class A Common Unit to purchasers in the offering(3)(4) | ||||||||
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| (1) | Determined by dividing the pro forma net tangible book value of our net assets immediately prior to the offering by the number of Class A Common Units held by the Existing Owners, after giving effect to the Reorganization Transactions. |
| (2) | Determined by dividing our pro forma as adjusted net tangible book value, after giving effect to the application of the net proceeds of Class A Common Units in this offering, by the total number of Class A Common Units to be outstanding after this offering after giving effect to the Reorganization Transactions. |
| (3) | If the initial public offering price were to increase or decrease by $ per Class A Common Unit, then dilution in pro forma net tangible book value per Class A Common Unit would equal $ and $ , respectively. |
| (4) | Because the total number of Units outstanding following the consummation of this offering will be impacted by any exercise of the underwriters’ option to purchase additional Class A Common Units and any net proceeds from such exercise will be retained by us, there will be a change to the dilution in pro forma net tangible book value per Class A Common Unit to purchasers in the offering due to any such exercise of the underwriters’ option to purchase additional Class A Common Units. |
A $1.00 increase (decrease) in the assumed initial public offering price of $ per Class A Common Unit, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease)
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our as adjusted pro forma net tangible book value per Class A Common Unit after this offering by $ per Class A Common Unit and increase (decrease) the dilution to new investors in this offering by $ per Class A Common Unit, assuming the number of Class A Common Units offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions, estimated offering expenses and the structuring fee payable by us.
The following table summarizes, on an adjusted pro forma basis as of June 30, 2024, the total number of Class A Common Units owned by the Existing Owners, and to be owned by new investors purchasing Class A Common Units in this offering, the total consideration paid, and the average price per Class A Common Unit paid by the Existing Owners and to be paid by new investors purchasing Class A Common Units in this offering at our initial public offering price of $ per Class A Common Unit, calculated before deduction of estimated underwriting discounts and commissions:
| Class A Common Units Acquired | Total Consideration | |||||||||||||||
| Number | Percent | Amount | Percent | |||||||||||||
| (in thousands) | ||||||||||||||||
Existing Owners | % | $ | % | |||||||||||||
Purchasers in the offering | % | $ | % | |||||||||||||
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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “—Assumptions and Considerations” below. In addition, you should read “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.
Distributions to Class A Common Unitholders
Our partnership agreement requires us to distribute all of our Available Cash, if any. Our cash distribution policy reflects a basic judgment that our unitholders generally will be better served by our re-investing a portion of our cash flow sufficient to generate meaningful annual production growth and distributing our remaining cash, after expenses and cash reserves, rather than distributing all of it. Our general partner intends to maintain a significant cash reserve in the Partnership.
Generally, we define “Available Cash” as cash on hand at the end of such quarter, plus certain distributions or dividends received after the end of the quarter, plus certain working capital borrowings and proceeds from this offering if determined by our general partner, less cash reserves established by our general partner, including for the proper conduct of our business, such as for capital expenditures, acquisitions, debt service, compliance with law and loan agreements and future distributions. We may, but are under no obligation to, borrow funds to make quarterly cash distributions to Class A Common Unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused Available Cash to be insufficient to pay the distribution at the current level.
Under our current cash distribution policy, within 90 days after the end of each quarter, beginning with the quarter ending , 2024, we intend to make quarterly distributions of all of our Available Cash to the holders of our Class A Common Units. However, other than the requirement in our partnership agreement to distribute all of our Available Cash each quarter, we have no legal obligation to make quarterly cash distributions of our Available Cash, and our general partner has considerable discretion to determine the amount of Available Cash for distribution each quarter. Our goal is to make a distribution of at least $ per Class A Common Unit per quarter (adjusted for the number of days in the first quarterly period after the closing date of this offering), which we refer to as our initial target quarterly distribution. Our goal is to make consistent quarterly distributions of Available Cash to our Class A Common Unitholders at or above our initial target quarterly distribution amount that grow over time. The record date for Class A Common Unitholders to receive each quarterly cash distribution will be set by our general partner at least ten (10) business days before the distribution payment date. However, to the extent there is no Available Cash, our partnership agreement does not require us to pay distributions on our Class A Common Units on a quarterly basis or otherwise.
Our general partner will receive 10% of the amount distributed above the initial target quarterly distribution per Class A Common Unit after the sixth full calendar quarter following the consummation of this offering (and also share in distributions from capital surplus, liquidating distributions and distributions of proceeds from any sale of our investment in PSI).
To the extent that our ability to transfer cash from any of our operating subsidiaries to the Partnership is restricted under the Existing Credit Agreement or the New Credit Facility, which we are in the process of negotiating, burdening our assets, or our cash flow from operations is insufficient to fully or partially fund a distribution on the Class A Common Units, our general partner will have the discretion to make cash distributions to Class A Common Unitholders from cash reserves at the Partnership level, including from the net proceeds of this offering initially designated as reserves.
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Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
Although our partnership agreement requires that we distribute all of our Available Cash, if any, quarterly, there is no guarantee that we will make quarterly cash distributions to our Class A Common Unitholders at the initial target quarterly distribution amount, or at all, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our Available Cash and cash reserves each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:
| • | Our cash distribution policy may be subject to restrictions on distributions under the Existing Credit Agreement or our New Credit Facility, which we are in the process of negotiating, or other debt agreements that we may enter into in the future. Specifically, our Existing Credit Agreement contains, and we anticipate that our New Credit Facility will contain, financial tests and covenants that we must satisfy in order to pay distributions. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements—Existing Credit Agreement” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of our Future Results of Operations to Our Historical Results of Operations—New Credit Facility.” Should we be unable to satisfy these covenants, or if a default or event of default occurs under our Existing Credit Agreement or New Credit Facility, we would be prohibited from making cash distributions to our Class A Common Unitholders notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions. |
| • | The amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Specifically, our general partner will have the authority to establish cash reserves for the prudent conduct of our business and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders. If our general partner does not set aside sufficient cash reserves or make sufficient cash expenditures to maintain the current production levels over the long-term of our oil and natural gas properties, we will be unable to pay any cash distributions from cash generated from operations. Our general partner intends to maintain a significant cash reserve in the Partnership. We are unlikely to be able to sustain our current level of distributions without making capital expenditures on development drilling or acquisitions that maintains the current production levels of our oil and natural gas properties. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may have the effect of, and may effectively represent, a return of part of our unitholders’ investment in us as opposed to a return on our unitholders’ investment. |
| • | Prior to making any cash distribution on our Class A Common Units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our Class A Common Unitholders. |
| • | Although our partnership agreement requires us to distribute all of our Available Cash, if any, to our Class A Common Unitholders, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may be amended with the consent of our general partner and the approval of the holders of a majority of our |
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outstanding Class A Common Units and Class B Common Units (including any such Class A Common Units and Class B Common Units held by our general partner, its members and their respective affiliates), voting together as a single class. Immediately upon the consummation of this offering, the Sponsors will control our general partner, and investment partnerships managed by Yorktown will own approximately % of our outstanding Class A Common Units and Class B Common Units, voting as a single class. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.” Our general partner has significant discretion to calculate the amount of Available Cash and amount of distributions to our Class A Common Unitholders. |
| • | Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner. |
| • | Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to any of our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. |
| • | We may lack sufficient Available Cash to pay distributions to our Class A Common Unitholders due to a number of factors, including decreases in commodity prices, decreases in our oil and natural gas production or increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements or anticipated cash needs. |
| • | To the extent that our Distributable Cash from Operations is insufficient to pay the initial target quarterly distribution or the level of distribution estimated to be paid in future quarters to the Class A Common Unitholders or to the extent we are restricted in our ability to transfer cash from our operating subsidiaries, we will still have the option to use the proceeds of this offering initially designated as reserves to pay a quarterly cash distribution to Class A Common Unitholders, but we will also have the ability to reduce our quarterly cash distribution in order to service or repay our debt, fund maintenance or grow capital expenditures. |
| • | While our Class B Common Units are not entitled to cash distributions (other than distributions of Available Cash from capital surplus, distributions of proceeds from the sale of our investment in PSI and liquidating distributions), those units are mandatorily convertible (at the election of our general partner) into Class A Common Units based upon an excess Distributable Cash from Operations coverage test. See “Description of Our Securities—Conversion of Class B Common Units.” |
Our Partnership Agreement Requires That We Distribute All of Our Available Cash, if Any, Which Could Limit Our Ability to Grow
Our partnership agreement requires us to distribute all of our Available Cash, if any, to our Class A Common Unitholders on a quarterly basis. Even though our general partner maintains significant flexibility on its ability to establish cash reserves, our growth may not be as fast as businesses that reinvest a higher portion of their cash to expand ongoing operations. Further, we may rely upon our cash reserves, including the net proceeds that we will receive in this offering and external financing sources, including borrowings under our Existing Credit Agreement or New Credit Facility and the issuance of other debt and equity securities, to fund future capital expenditures on development and acquisitions. Following the completion of this offering, we expect that we will need to utilize the public equity or debt markets and bank financings to fund future development, capital expenditures and acquisitions. To the extent we require external sources of capital to fund our growth and are unable to access such sources, the requirement in our partnership agreement to distribute all of our Available Cash and our current cash distribution policy may impair our ability to grow. Our Existing Credit Agreement does, and our New Credit Facility may, and any future debt agreements may, limit our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Related to Our Indebtedness—Our Existing Credit Agreement contains restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.” To the extent we issue additional Class A Common Units, including through conversion of the Class B Common Units, the payment of distributions on
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those additional Class A Common Units may increase the risk that we will be unable to maintain or increase our cash distributions per Class A Common Unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our Class A Common Units, and our Class A Common Unitholders will have no preemptive or other rights (solely as a result of their status as Class A Common Unitholders) to purchase any such additional units. If we incur additional debt to finance our growth strategy, we will have increased interest expense, which in turn will reduce the Available Cash that we have to distribute to our unitholders. See “Risk Factors—Risks Inherent in an Investment in Us—Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.”
Unaudited Pro Forma Distributable Cash from Operations for the Year Ended December 31, 2023 and the Twelve Months Ended June 30, 2024
If we had completed the transactions contemplated in this prospectus on January 1, 2023, our pro forma Distributable Cash from Operations would have been approximately $15.4 million for the year ended December 31, 2023 and $14.5 million for the twelve months ended June 30, 2024, which would have been sufficient to pay our initial target quarterly distributions for the quarters in those periods. To the extent that our Distributable Cash from Operations had been insufficient to pay our initial target quarterly distributions, all or a portion of the quarterly cash distributions to our Class A Common Unitholders would have been made from our cash on hand, including from proceeds from this offering initially designated as reserves.
Upon the completion of this offering, we expect to incur incremental non-recurring costs related to our transition to a publicly traded partnership, including the costs of this initial public offering and the costs associated with the initial implementation of our internal control implementation and testing. We also expect to incur additional recurring costs related to being a public company, including costs associated with the employment of additional personnel, compliance under the Exchange Act and applicable securities exchange requirements, annual and quarterly reports to be filed with the SEC, tax return preparation, independent auditor fees, incremental legal fees, investor relations activities, registrar and transfer agent fees, and incremental director and officer liability insurance costs. The direct, incremental general and administrative expenses are not included in our historical or pro forma financial statements; however, we expect those expenses to be approximately $2.5 million per year. These costs are not included in our unaudited pro forma Distributable Cash from Operations calculation below.
The pro forma financial statements appearing elsewhere in this prospectus, from which pro forma Distributable Cash from Operations is derived, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, Distributable Cash from Operations is a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma Distributable Cash from Operations stated above in the manner described in the table below. As a result, the amount of pro forma Distributable Cash from Operations should only be viewed as a general indication of the amount of Distributable Cash from Operations that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.
The following table illustrates, on an unaudited pro forma basis for the year ended December 31, 2023 and the twelve months ended June 30, 2024, the amount of Distributable Cash from Operations that would have been available for distribution to our Class A Common Units, assuming in each case that this offering had been consummated on January 1, 2023.
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Peak Resources LP
Unaudited Pro Forma Distributable Cash from Operations
| Pro Forma | ||||||||
| Year Ended December 31, 2023 | Twelve Months Ended June 30, 2024 | |||||||
| (in thousands, except per unit data) | ||||||||
Net Loss(1) | $ | (90,623 | ) | $ | (98,737 | ) | ||
Interest expense (net of interest income)(2) | 8,867 | 9,005 | ||||||
Income tax provision (benefit) | (24,138 | ) | (26,247 | ) | ||||
Depreciation, depletion and amortization | 28,801 | 22,688 | ||||||
Impairment of oil and natural gas properties(3) | 111,871 | 111,871 | ||||||
Accretion | 227 | 230 | ||||||
Exploration expenses | — | — | ||||||
Non-cash gains on commodity derivatives | (5,266 | ) | — | |||||
Non-cash incentive compensation expenses | — | — | ||||||
Non-cash (gain) loss on extinguishment of debt | 1,080 | — | ||||||
Non-cash (gain) loss on investment in PSI | — | — | ||||||
Abandonment | 2,932 | 2,040 | ||||||
Other | — | — | ||||||
Adjusted EBITDAX(4) | 33,751 | 20,850 | ||||||
Cash interest expense, net of interest income(2) | (9,306 | ) | (6,051 | ) | ||||
Maintenance capital expenditures(5) | (349 | ) | — | |||||
Expansion capital expenditures(5) | (8,732 | ) | (321 | ) | ||||
Acquisition costs | — | (13 | ) | |||||
Cash income tax payments | — | — | ||||||
Reimbursement of general partner expenses | — | — | ||||||
Other | — | |||||||
Distributable Cash from Operations(6)(7) | $ | 15,364 | $ | 14,465 | ||||
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Pro Forma Available Cash for Distribution | ||||||||
Pro Forma Annualized Distributions per Class A Common Unit | ||||||||
Pro Forma Estimated Annual Cash Distributions: | ||||||||
Distributions on Class A Common Units held by purchasers in this offering | ||||||||
Distributions on Class A Common Units held by affiliates of our general partner | ||||||||
Total estimated annual cash distributions | ||||||||
| (1) | Pro forma net loss reflects a pro forma income tax benefit of $24.1 million for the year ended December 31, 2023 and $26.2 million for the twelve months ended June 30, 2024, all of which is associated with the income tax effects of the corporate reorganization described under “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction” and this offering. Our predecessor was not subject to U.S. federal income tax at an entity level. As a result, the consolidated net loss in our historical financial statements does not reflect the tax expense or benefit we would have incurred if we were subject to U.S. federal income tax at an entity level during such periods. |
| (2) | The following table provides a reconciliation of cash interest expense, net of interest income, to interest expenses, net of interest income: |
| Year Ended December 31, 2023 | Twelve Months Ended June 30, 2024 | |||||||
Interest expense, net of interest income | $ | 8,867 | $ | 9,005 | ||||
(Decrease in) accrued interest expense | 439 | (2,016 | ) | |||||
Amortization of deferred finance cost | — | (938 | ) | |||||
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Cash interest expense, net of interest income | $ | 9,306 | $ | 6,051 | ||||
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| (3) | Impairment for the year ended December 31, 2023 and the twelve months ended June 30, 2024 was primarily due to a decrease in the value of proved oil and natural gas reserves as a result of lower oil and natural gas prices at December 31, 2023 and June 30, 2024, respectively as well as SEC guidelines on development pace. For the year ended December 31, 2023, oil and natural gas prices calculated in accordance with SEC guidelines decreased by 16.5% and 58.5%, respectively, as compared to the year ended December 31, 2022. |
| (4) | Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our operating results. “The Offering—Non-GAAP Financial Measures” contains a description of Adjusted EBITDAX and a reconciliation to our net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
| (5) | Expansion capital expenditures are those capital expenditures that increase the operating capacity of, or the revenue generated by, our capital assets. Maintenance capital expenditures are those capital expenditures required to maintain, over the long-term, the operating capacity of, or the revenue generated by, our capital assets. |
| (6) | Distributable Cash from Operations is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. “The Offering—Non-GAAP Financial Measures” contains a description of Distributable Cash from Operations and a reconciliation to net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
| (7) | If we had completed the transactions contemplated in this prospectus on January 1, 2023, our pro forma Distributable Cash from Operations would have been sufficient to pay our initial target quarterly distributions for the quarters in both periods. To the extent that our Distributable Cash from Operations had been insufficient to pay our initial target quarterly distributions, a portion of the quarterly cash distributions to our Class A Common Unitholders would have been made from our cash on hand, including from proceeds from this offering initially designated as reserves. |
Estimated Distributable Cash from Operations for the Twelve Months Ending June 30, 2025 and the Twelve Months Ending December 31, 2025
The financial forecast presents, to the best of our knowledge and belief, our expected results of operations, Adjusted EBITDAX and Distributable Cash from Operations for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025. Based upon the assumptions and considerations set forth in the table below, we forecast that our estimated Distributable Cash from Operations for the twelve months ending June 30, 2025 will be approximately $8.3 million, which would have been sufficient to support the payment of our initial target quarterly distributions for the quarters in the twelve months ending June 30, 2025. Further, based upon the assumptions and considerations set forth in the table below, we forecast that our estimated Distributable Cash from Operations for the twelve months ending December 31, 2025 will be insufficient to pay our initial target quarterly distribution of $ per Class A Common Unit for each of the quarters presented. As a result, we forecast that a portion of the quarterly cash distributions to our Class A Common Unitholders for the twelve months ending December 31, 2025 will be made from our cash on hand, including partially from proceeds from this offering initially designated as reserves. The number of outstanding Class A Common Units on which we have based such belief does not include (i) any Class A Common Units that may be issued under the long-term incentive plan that our general partner is expected to adopt, or (ii) the issuance of any Class A Common Units upon mandatory conversion of Class B Common Units. Furthermore, the financial forecast assumes that we do not make any acquisitions of properties during the twelve months ending June 30, 2025 or the twelve months ending December 31, 2025, except as reflected in maintenance capital expenditures.
Our Statement of Estimated Adjusted EBITDAX and Distributable Cash from Operations reflects our judgment, as of the date of this prospectus, of conditions we expect to exist and the course of action we expect to take for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025, as applicable. The assumptions discussed below under “—Assumptions and Considerations” are those that we believe are significant to our ability to generate the requisite Adjusted EBITDAX and Distributable Cash from Operations. Based on such assumptions, we believe our actual results of operations, cash flow and proceeds from this offering will be sufficient to generate the Adjusted EBITDAX and Distributable Cash from Operations
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necessary to pay the $ annualized cash distribution. We cannot, however, give you any assurance that we will generate this amount. There will likely be differences between our estimated Adjusted EBITDAX and Distributable Cash from Operations and our actual results, and those differences could be material. If we fail to generate the estimated Adjusted EBITDAX and Distributable Cash from Operations contained in our forecast, our annualized cash distribution to our Class A Common Unitholders may be less than expected. We can give you no assurance that our assumptions will be realized or that we will generate any Available Cash, in which event we will not be able to pay quarterly cash distributions from our Available Cash to our Class A Common Unitholders.
While we do not as a matter of course make public projections as to future sales, earnings or other results, our management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDAX and Distributable Cash from Operations below to substantiate our belief that we will have sufficient Available Cash to pay the forecasted $ cash distribution on all our Class A Common Units for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025. This forecast is a forward-looking statement and should be read together with our historical financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate Adjusted EBITDAX and Distributable Cash from Operations necessary for us to pay cash distributions on all of our outstanding Class A Common Units for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025 equal to $ per Class A Common Unit. Readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read “—Assumptions and Considerations,” including the sensitivity analysis included therein.
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Our independent registered public accounting firm has not compiled, examined or performed any procedures with respect to the accompanying prospective financial information and, accordingly, our independent registered public accounting firm does not express an opinion or any other form of assurance with respect thereto. The reports of our independent registered public accounting firm included in the registration statement relate to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.
When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate Adjusted EBITDAX and Distributable Cash from Operations necessary to pay the forecasted aggregate annualized cash distribution of $ on all of our outstanding Class A Common Units for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025.
We are providing the Statement of Estimated Adjusted EBITDAX and Distributable Cash from Operations to supplement our historical financial statements and unaudited pro forma condensed combined financial statements and in support of our belief that we will have sufficient Available Cash to pay the forecasted aggregate annualized cash distribution of $ on all of our outstanding Class A Common Units for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025. Please read below under “—Assumptions and Considerations” for further information about the assumptions we have made for the financial forecast.
We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or
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circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.
Our Estimated Available Cash for Distribution
The following table shows how we calculate estimated Adjusted EBITDAX and Distributable Cash from Operations and Available Cash for the twelve months ending June 30, 2025, for the twelve months ending December 31, 2025 and for each quarter during those twelve-month periods that would be available for distribution to our Class A Common Unitholders. All of the amounts for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025 in the table below are estimates. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Assumptions and Considerations.”
Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical financial statements. These reports do not extend to the table and the related forecasted information contained in this section and should not be read to do so.
Based on our current financial projections, a portion of the quarterly Class A Common Unit cash distributions through December 31, 2025 is expected to be made from our cash on hand, including partially from proceeds of this offering initially designated as reserves.
| Three Months Ending September 30, 2024 | Three Months Ending December 31, 2024 | Three Months Ending March 31, 2025 | Three Months Ending June 30, 2025 | Three Months Ending September 30, 2025 | Three Months Ending December 31, 2025 | Twelve Months Ending June 30, 2025 | Twelve Months Ending December 31, 2025 | |||||||||||||||||||||||||
| (in thousands, except per unit data) | ||||||||||||||||||||||||||||||||
Estimated Net Income (Loss)(1) | $ | (2,349 | ) | $ | 4,140 | $ | (1,828 | ) | $ | 2,735 | $ | 3,473 | $ | 11,118 | $ | 2,699 | $ | 15,498 | ||||||||||||||
Interest expense, net of interest income | 1,859 | 176 | 300 | 294 | 294 | 291 | 2,629 | 1,179 | ||||||||||||||||||||||||
Income tax provision (benefit) | (624 | ) | 1,101 | (486 | ) | 727 | 923 | 2,956 | 717 | 4,120 | ||||||||||||||||||||||
Depreciation, depletion and amortization | 5,773 | 5,743 | 5,099 | 7,915 | 11,273 | 15,080 | 24,530 | 39,367 | ||||||||||||||||||||||||
Impairment of oil and natural gas properties | — | — | — | — | — | — | ||||||||||||||||||||||||||
Accretion | 58 | 59 | 59 | 61 | 64 | 66 | 237 | 250 | ||||||||||||||||||||||||
Exploration expenses | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Non-cash (gain) loss on commodity derivatives | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Non-cash incentive compensation expenses | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Non-cash (gain) loss on extinguishment of debt | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Non-cash (gain) loss on investment in PSI | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Abandonment | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Other (gain) loss | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Adjusted EBITDAX(2) | 4,717 | 11,219 | 3,144 | 11,732 | 16,027 | 29,511 | 30,812 | 60,414 | ||||||||||||||||||||||||
Cash interest expense, net of interest income | (1,859 | ) | (176 | ) | (300 | ) | (294 | ) | (294 | ) | (291 | ) | (2,629 | ) | (1,179 | ) | ||||||||||||||||
Development costs(3) | (1,156 | ) | (2,304 | ) | (4,885 | ) | (11,566 | ) | (28,388 | ) | (26,217 | ) | (19,911 | ) | (71,056 | ) | ||||||||||||||||
Acquisition costs | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Cash income tax payments | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Reimbursement of general partner expenses | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Other | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
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| Three Months Ending September 30, 2024 | Three Months Ending December 31, 2024 | Three Months Ending March 31, 2025 | Three Months Ending June 30, 2025 | Three Months Ending September 30, 2025 | Three Months Ending December 31, 2025 | Twelve Months Ending June 30, 2025 | Twelve Months Ending December 31, 2025 | |||||||||||||||||||||||||
| (in thousands, except per unit data) | ||||||||||||||||||||||||||||||||
Estimated Distributable Cash from Operations(4) | $ | 1,702 | $ | 8,739 | $ | (2,041 | ) | $ | (128 | ) | $ | (12,566 | ) | $ | 3,003 | $ | 8,272 | $ | (11,821 | ) | ||||||||||||
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Estimated Available Cash for Distribution(5) | ||||||||||||||||||||||||||||||||
Estimated Cash Distributions per Class A Common Unit | ||||||||||||||||||||||||||||||||
Estimated Cash Distribution | ||||||||||||||||||||||||||||||||
Distributions on Class A Common Units held by Purchasers in this Offering | ||||||||||||||||||||||||||||||||
Distributions on Class A Common Units held by our General Partner in this Offering | ||||||||||||||||||||||||||||||||
Distributions on Class A Common Units held by Existing Investors in this Offering | ||||||||||||||||||||||||||||||||
Total Estimated Cash Distributions to Class A Common Unitholders | ||||||||||||||||||||||||||||||||
| (1) | Pro forma net loss reflects a pro forma income tax benefit which is associated with the income tax effects of the reorganization described under “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refining Transaction—Reorganization Transactions and Partnership Structure” and this offering. Our predecessor was not subject to U.S. federal income tax at an entity level. As a result, the consolidated net loss in our historical financial statements does not reflect the tax expense or benefit we would have incurred if we were subject to U.S. federal income tax at an entity level during such periods. |
| (2) | Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our operating results. “The Offering—Non-GAAP Financial Measures” contains a description of Adjusted EBITDAX and a reconciliation to our net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
| (3) | Development costs include all of our capital expenditures for oil and natural gas properties, other than acquisitions. |
| (4) | Distributable Cash from Operations is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. “The Offering—Non-GAAP Financial Measures” contains a description of Distributable Cash from Operations and a reconciliation to net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
| (5) | Based on our current financial projections, all or a portion of the quarterly cash distributions to our Class A Common Unitholders through December 31, 2025 is expected to be made from our cash on hand, including partially from proceeds of this offering initially designated as reserves. |
Assumptions and Considerations
Based upon the specific assumptions outlined below, we expect to generate Distributable Cash from Operations for the twelve months ending June 30, 2025 of approximately $8.3 million. This amount would pay the initial target quarterly distributions of $ per Class A Common Unit for each of the four quarters for the twelve months ending June 30, 2025. Based on our current financial projections, all or a portion of the quarterly Class A Common Unit cash distributions for the four quarters in the twelve months ending December 31, 2025 is expected to be made from our cash on hand, including partially from proceeds of this offering initially designated as reserves.
While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to
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significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. It is also important to note that we will hold a minority ownership interest in PSI and will not control PSI, have any control over the size of dividends paid by PSI or have any control over whether dividends are paid at all. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate, in which event the market price of our Class A Common Units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.
Upon the completion of this offering, we expect to incur incremental non-recurring costs related to our transition to a publicly traded partnership, including the costs of this initial public offering and the costs associated with the initial implementation of our internal control implementation and testing. We also expect to incur additional recurring costs related to being a public company, including costs associated with the employment of additional personnel, compliance under the Exchange Act and applicable securities exchange requirements, annual and quarterly reports to be filed with the SEC, tax return preparation, independent auditor fees, incremental legal fees, investor relations activities, registrar and transfer agent fees, and incremental director and officer liability insurance costs. The direct, incremental general and administrative expenses are included in our financial forecast of Available Cash for distribution for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025. We expect those expenses to be approximately $2.5 million per year.
Operations and Revenue
Production. Our ability to generate sufficient cash from operations to pay cash distributions to Class A Common Unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. Production volumes directly impact our revenue. Any negative effect on production volumes could have a material adverse effect on our business, financial condition, results of operations and Distributable Cash from Operations. Our existing production will naturally decline over time as the applicable reservoir is depleted. As of June 30, 2024, the decline rate for our existing oil and natural gas properties over the next twelve months in the Powder River Basin is approximately 15-20%.
The following table presents historical production volumes for our properties on a pro forma basis for the year ended December 31, 2023 and the twelve months ended June 30, 2024 and on a forecasted basis for the twelve months ending June 30, 2025 and the twelve months ended December 31, 2025:
| Pro Forma Year Ended December 31, 2023 | Pro Forma Twelve Months Ended June 30, 2024 | Forecasted Twelve Months Ending June 30, 2025 | Forecasted Twelve Months Ending December 31, 2025 | |||||||||||||
Annual production: | ||||||||||||||||
Oil and condensate (MBbl) | 625 | 588 | 572 | 1,112 | ||||||||||||
Natural gas (MMcf)(1) | 2,705 | 2,511 | 2,960 | 3,582 | ||||||||||||
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Total (Mboe) | 1,076 | 1,006 | 1,065 | 1,709 | ||||||||||||
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Average net daily production: | ||||||||||||||||
Oil and condensate (Bbls/d) | 1,712 | 1,606 | 1,566 | 3,047 | ||||||||||||
Natural gas (Mcf/d)(1) | 7,410 | 6,862 | 8,108 | 9,814 | ||||||||||||
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Total (Boe/d) | 2,947 | 2,749 | 2,918 | 4,683 | ||||||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our pricing and natural gas production. |
We estimate that our total oil and natural gas production for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025 will be 2,918 Boe per day and 4,683 Boe per day, respectively, as compared
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to 2,947 Boe per day on a pro forma basis for the year ended December 31, 2023 and 2,749 Boe per day on a pro forma basis for the twelve months ended June 30, 2024. We intend to grow our forecasted production level to 1,065 Mboe and 1,709 Mboe for the twelve months ending June 30, 2025 and December 31, 2025, respectively.
Prices. Our results of operations depend on many factors, particularly the price of our commodity production and our ability to market our production effectively. Oil and natural gas prices have historically been volatile, and this volatility is expected to continue in the future. During the period from January 1, 2023 through June 30, 2024, our settled prices for crude oil and natural gas reached a high of $92.92 per Bbl and $5.018 per MMBtu, respectively, and a low of $66.02 per Bbl and $1.991 per MMBtu, respectively. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our New Credit Facility, which we are in the process of negotiating, and which is expected to be redetermined semi-annually.
The NYMEX WTI, for oil prices, and NYMEX Henry Hub, for gas prices, are widely used benchmarks for the pricing of oil, NGL and natural gas in the United States. The price we receive for our oil and natural gas production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. The differentials to published oil and natural gas prices are based upon our analysis of the historic price differentials for production from the mineral interests with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur. The table below illustrates the relationship between average oil and natural gas realized sales prices and average NYMEX futures prices as of December 31, 2023 on a pro forma basis for the year ended December 31, 2023 and the twelve months ended June 30, 2024, as well as our forecast for the twelve months ending June 30, 2025 and the twelve months ending December 31 2025:
| Pro Forma Year Ended December 31, 2023 | Pro Forma Twelve Months Ended June 30, 2024 | Forecasted Twelve Months Ending June 30, 2025 | Forecasted Twelve Months Ending December 31, 2025 | |||||||||||||
Average oil sales prices ($/Bbl): | ||||||||||||||||
Average daily NYMEX-WTI oil price | $77.32 | $79.53 | $78.30 | $75.13 | ||||||||||||
Differential to NYMEX-WTI oil | (1.28) | (1.79) | (2.67) | (2.00) | ||||||||||||
Realized oil sales price (excluding derivatives) | 76.04 | 77.74 | 75.63 | 73.13 | ||||||||||||
Realized oil sales price (including derivatives) | 70.12 | 72.75 | 67.38 | 70.48 | ||||||||||||
Average natural gas sales prices ($/Mcf)(1): | ||||||||||||||||
Average daily NYMEX-Henry Hub natural gas price | $ | 2.79 | $ | 2.48 | $ | 3.10 | $ | 3.48 | ||||||||
Differential to NYMEX-Henry Hub natural gas | (0.34 | ) | (0.36 | ) | (0.30 | ) | (0.30 | ) | ||||||||
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| Pro Forma Year Ended December 31, 2023 | Pro Forma Twelve Months Ended June 30, 2024 | Forecasted Twelve Months Ending June 30, 2025 | Forecasted Twelve Months Ending December 31, 2025 | |||||||||||||
Realized natural gas sales price (excluding derivatives) | 2.45 | 2.12 | 2.80 | 3.18 | ||||||||||||
Realized natural gas sales price (including derivatives) | 2.46 | 2.68 | 3.03 | 3.22 | ||||||||||||
| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in the natural gas price. |
Hedging Activities. We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations and to satisfy the requirement under our Existing Credit Agreement to hedge, on a rolling quarterly basis, reasonably anticipated projected production of proved developed producing reserves we are required to hedge. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk—Commodity Derivatives” for more information.
Our commodity derivative contracts consist of swap and collar agreements based upon NYMEX-WTI prices. The table below shows the volumes and prices covered by the commodity derivative contracts for the twelve months ending June 30, 2025. Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas production and reserves. For purposes of our forecast, we have assumed that we will not enter into additional natural gas or oil derivative contracts during the forecast period, although we may do so on an opportunistic basis if market conditions are favorable. See “Risk Factors—We use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk.”
| Swaps | Collars(1) | |||||||||||||||
| Volume per Day | Weighted Avg. Floor Price | Volume per Day | Weighted Avg. Floor Price | |||||||||||||
Oil: | ||||||||||||||||
July 2024-June 2025 (Bbl/d) | 782 | $ | 67.40 | 236 | $ | 62.63 | ||||||||||
% of Forecasted Production | 50% | 15% | ||||||||||||||
Natural Gas(2): | ||||||||||||||||
July 2024-June 2025 (MMBtu/d) | 2,713 | $ | 3.60 | 802 | $ | 3.02 | ||||||||||
% of Forecasted Production | 33% | 10 | ||||||||||||||
| (1) | Statistics reflect periods in which derivative instruments exist such that period averages are not affected by periods with no hedged volumes. |
| (2) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in the natural gas price and in our natural gas production. |
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Operating Revenues and Realized Commodity Derivative Gains. The following table illustrates the primary components of operating revenues and realized commodity derivative gains on a pro forma basis for the year ended December 31, 2023 and the twelve months ended June 30, 2024 as well as on a forecasted basis for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025:
| Pro Forma Year Ended December 31, 2023 | Pro Forma Twelve Months Ended June 30, 2024 | Forecasted Twelve Months Ending June 30, 2025 | Forecasted Twelve Months Ending December 31, 2025 | |||||||||||||
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Oil: | ||||||||||||||||
Oil revenues (excluding the effects of derivative instruments) | $ | 47,517 | $ | 45,544 | $ | 43,133 | $ | 80,721 | ||||||||
Realized oil derivative instruments gain (loss) | (3,702 | ) | (2,935 | ) | (3,609 | ) | (2,951 | ) | ||||||||
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Total | $ | 43,815 | $ | 42,609 | $ | 39,524 | $ | 77,770 | ||||||||
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Natural Gas revenues (excluding the effects of derivative instruments) | $ | 6,616 | $ | 5,294 | $ | 8,258 | $ | 11,426 | ||||||||
Realized natural gas derivative instruments gain (loss) | 40 | 1,397 | 563 | 139 | ||||||||||||
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Total | $ | 6,656 | $ | 6,691 | $ | 8,821 | $ | 11,565 | ||||||||
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Total: | ||||||||||||||||
Operating revenues | $ | 54,133 | $ | 50,838 | $ | 51,391 | $ | 92,147 | ||||||||
Commodity derivative instruments gain (loss) | (3,662 | ) | (1,538 | ) | (3,046 | ) | (2,812 | ) | ||||||||
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Operating revenue and realized commodity derivative instrument gains (losses) | $ | 50,471 | $ | 49,300 | $ | 48,345 | $ | 89,335 | ||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas revenue. |
Expenses
Development Costs. Our estimated development costs for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025 of $19.9 million and $71.1 million, respectively, represent our estimate of the average annual capital expenditures necessary to achieve our forecasted production level of 2,918 Boe per day for the twelve months ended June 30, 2025 and 4,683 Boe per day for the twelve months ending December 31, 2025, respectively.
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Production Expenses. The following table summarizes production expenses on an aggregate basis and on a per Boe basis on a pro forma basis for the year ended December 31, 2023 and the twelve months ended June 30, 2024 as well as on a forecasted basis for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025:
| Pro Forma Year Ended December 31, 2023 | Pro Forma Twelve Months Ended June 30, 2024 | Forecasted Twelve Months Ending June 30, 2025 | Forecasted Twelve Months Ending December 31, 2025 | |||||||||||||
Production expenses (in thousands) | $ | 13,949 | $ | 13,507 | $ | 12,857 | $ | 15,446 | ||||||||
Production expenses (per Boe) | $ | 12.97 | $ | 13.43 | $ | 12.07 | $ | 9.04 | ||||||||
We estimate that our production expenses for the twelve months ending June 30, 2025 will be approximately $12.9 million and $15.4 million for the twelve months ending December 31, 2025. Production expenses consist of lease operating expenses incurred for the operation and maintenance of wells and related equipment. On a pro forma basis, for the year ended December 31, 2023 and the twelve months ended June 30, 2024, production expenses were approximately $13.9 million and $13.5 million, respectively. It is anticipated that production expenses on a per Boe basis will continue to decrease due to higher production and forecasted lower commodity prices.
Production and Ad Valorem Taxes. Production and ad valorem taxes consist primarily of severance taxes and ad valorem taxes. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by state or local taxing authorities. In general, the severance taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. We evaluate production and ad valorem taxes on a per Boe basis to monitor costs to ensure that they are at acceptable levels. These can also be influenced by acquisitions, commodity prices, changes in values of our properties, sales mix and acquisitions. It is anticipated that production and ad valorum taxes on a per Boe basis will continue to decrease due to higher production and forecasted lower commodity prices.
The following table summarizes production and ad valorem taxes on a pro forma basis for the year ended December 31, 2023 and the twelve months ended June 30, 2024, as well as on a forecasted basis for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025:
| Pro Forma Year Ended December 31, 2023 | Pro Forma Twelve Months Ended June 30, 2024 | Forecasted Twelve Months Ending June 30, 2025 | Forecasted Twelve Months Ending December 31, 2025 | |||||||||||||
Production and ad valorem taxes (in thousands) | $ | 7,508 | $ | 6,856 | $ | 6,439 | $ | 11,391 | ||||||||
Production and ad valorem taxes (per Boe) | $ | 6.98 | $ | 6.82 | $ | 6.05 | $ | 6.67 | ||||||||
General and Administrative Expenses. General and administrative expenses consist primarily of personnel related costs and are partially offset by certain reimbursements of overhead expenses. In connection with the consummation of this offering, we expect to incur additional costs related to being a public company. However, we do not expect to experience a material change in our cash cost structure, except as maybe affected by the volatility of commodity prices, increased expenses as a publicly-traded limited partnership, the effectives of our commodity derivative contracts, the effects of impairment on our producing properties. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Factors Affecting the Comparability of Our Future Results of Operations to Our Historical Results of Operations.”
Interest Expense. Interest expense is primarily a result of interest on our borrowings on our Existing Credit Agreement and potentially, the New Credit Facility, to fund operations and acquisitions of properties as well as
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the amortization of debt issuance costs associated with these borrowings. Interest expense can fluctuate with our level of indebtedness as well as changes in interest rates and other fees under our credit agreements. We intend to use a portion of the net proceeds of this offering to repay a portion of the Existing Credit Agreement. Please see “Use of Proceeds” for additional information. We are in the process of negotiating the New Credit Facility with prospective lenders that we anticipate entering into after the completion of this offering. The amount, maturity, interest rates and other terms of the New Credit Facility are in the process of being negotiated with prospective lenders; however, we expect that the aggregate commitments thereunder will be approximately $150 million with an initial borrowing base of $45.0 million. We estimate that our cash interest expense for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025 will be approximately $2.6 million and $1.1 million, respectively, as compared to $8.9 million and $9.0 million on a pro forma basis for the year ended December 31, 2023 and the twelve months ended June 30, 2024, respectively.
Regulatory, Industry and Economic Factors
Our forecasts for the twelve months ending June 30, 2025 and the twelve months ending December 31, 2025 are based on the following significant assumptions related to regulatory, industry and economic factors:
| • | There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or any interpretation of existing regulations, that will be materially adverse to our business; |
| • | There will not be any material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor; |
| • | All supplies and commodities necessary for production and sufficient transportation will be readily available; |
| • | There will not be any major adverse change in commodity prices or the energy industry in general; |
| • | There will not be any material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events, including any events that could lead to force majeure under any of our marketing agreements; |
| • | There will not be any adverse change in the markets in which we operate resulting from supply or production disruptions, reduced demand for our product or significant changes in the market prices for our product; and |
| • | Market, insurance, regulatory and overall economic conditions will not change substantially. |
Sensitivity Analysis
Our ability to generate sufficient cash from operations to pay cash distributions to our Class A Common Unitholders is a function of two primary variables: (i) production volumes; and (ii) commodity prices. In the tables below, we illustrate the effect that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the forecasted cash distributions on our outstanding Class A Common Units for the twelve months ending June 30, 2025.
We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impracticable to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.
Production Volume Changes
Production volumes directly impact our revenue. Any negative effect on production volumes could have a material adverse effect on our business, financial condition, results of operations and Distributable Cash from Operations. The following table shows estimated Adjusted EBITDAX and Distributable Cash from Operations under production levels of 80%, 100% and 120% of the production level we have forecasted for the twelve
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months ending June 30, 2025 and for the twelve months ending December 31, 2025. The estimated Adjusted EBITDAX and Distributable Cash from Operations amounts shown below are based on the assumptions used in our forecast.
| Forecasted Twelve Months Ending June 30, 2025 | Forecasted Twelve Months Ending December 31, 2025 | |||||||||||||||||||||||
| Percentage of Forecasted Net Production | Percentage of Forecasted Net Production | |||||||||||||||||||||||
| 80% | 100% | 120% | 80% | 100% | 120% | |||||||||||||||||||
| (in thousands, except per unit amounts) | (in thousands, except per unit amounts) | |||||||||||||||||||||||
Forecasted net production(1): | ||||||||||||||||||||||||
Oil (MBbl) | 458 | 572 | 686 | 890 | 1,112 | 1,334 | ||||||||||||||||||
Natural gas (Mmcf) | 2,368 | 2,960 | 3,552 | 2,866 | 3,582 | 4,298 | ||||||||||||||||||
Total (Mboe) | 852 | 1,065 | 1,278 | 1,367 | 1,709 | 2,051 | ||||||||||||||||||
Oil (Bbl/d) | 1,253 | 1,566 | 1,879 | 2,438 | 3,047 | 3,656 | ||||||||||||||||||
Natural gas (Mcf/d) | 6,486 | 8,108 | 9,730 | 7,851 | 9,814 | 11,777 | ||||||||||||||||||
Total (Boe per day) | 2,334 | 2,918 | 3,502 | 3,746 | 4,683 | 5,620 | ||||||||||||||||||
Forecasted Prices(1): | ||||||||||||||||||||||||
NYMEX-WTI oil price (per Bbl) | 78.30 | 78.30 | 78.30 | 75.13 | 75.13 | 75.13 | ||||||||||||||||||
Realized oil sales price (per Bbl) (excluding derivatives) | 75.63 | 75.63 | 75.63 | 73.13 | 73.13 | 73.13 | ||||||||||||||||||
Realized oil sales price (per Bbl) (including derivatives) | 67.38 | 67.38 | 67.38 | 70.48 | 70.48 | 70.48 | ||||||||||||||||||
NYMEX- Henry Hub natural gas price (per Mcf) | 3.10 | 3.10 | 3.10 | 3.48 | 3.48 | 3.48 | ||||||||||||||||||
Realized natural gas sales price (per Mcf) (excluding derivatives) | 2.80 | 2.80 | 2.80 | 3.18 | 3.18 | 3.18 | ||||||||||||||||||
Realized natural gas sales price (per Mcf) (including derivatives) | 3.03 | 3.03 | 3.03 | 3.22 | 3.22 | 3.22 | ||||||||||||||||||
Estimated Net Income (Loss)(2) | $ | (559 | ) | $ | 2,699 | $ | 5,955 | $ | 9,138 | $ | 15,498 | $ | 21,849 | |||||||||||
Interest expense, net of interest income | 2,629 | 2,629 | 2,629 | 1,179 | 1,179 | 1,179 | ||||||||||||||||||
Income tax provision (benefit) | (148 | ) | 717 | 1,583 | 2,429 | 4,120 | 5,808 | |||||||||||||||||
Depreciation, depletion and amortization | 19,624 | 24,530 | 29,436 | 31,494 | 39,367 | 47,241 | ||||||||||||||||||
Impairment of oil and natural gas properties | — | — | — | — | — | — | ||||||||||||||||||
Accretion | 237 | 237 | 237 | 250 | 250 | 250 | ||||||||||||||||||
Exploration expenses | — | — | — | — | — | — | ||||||||||||||||||
Non-cash gain (loss) on commodity derivatives | — | — | — | — | — | — | ||||||||||||||||||
Non-cash incentive compensation expenses | — | — | — | — | — | — | ||||||||||||||||||
Non-cash (gain) loss on extinguishment of debt | — | — | — | — | — | — | ||||||||||||||||||
Non-cash (gain) loss on investment in PSI | — | — | — | — | — | — | ||||||||||||||||||
Abandonment | — | — | — | — | — | — | ||||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||
Estimated Adjusted EBITDAX(2) | $ | 21,783 | $ | 30,812 | $ | 39,840 | $ | 44,490 | $ | 60,414 | $ | 76,327 | ||||||||||||
Cash interest expense, net of interest income | (2,629 | ) | (2,629 | ) | (2,629 | ) | (1,179 | ) | (1,179 | ) | (1,179 | ) | ||||||||||||
Development costs | (19,911 | ) | (19,911 | ) | (19,911 | ) | (71,056 | ) | (71,056 | ) | (71,056 | ) | ||||||||||||
Acquisition costs | — | — | — | — | — | — | ||||||||||||||||||
Cash income tax payments | — | — | — | — | — | — | ||||||||||||||||||
Reimbursement of general partner expenses | — | — | — | — | — | — | ||||||||||||||||||
Distributable Cash from Operations(3) | $ | (757 | ) | $ | 8,272 | $ | 17,300 | $ | (27,745 | ) | $ | (11,821 | ) | $ | 4,092 | |||||||||
| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas production and reserves as well as in the natural gas price |
| (2) | Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our operating results. “The Offering—Non-GAAP Financial Measures” contains a description of Adjusted EBITDAX and a reconciliation to our net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
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| (3) | Distributable Cash from Operations is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. “The Offering—Non-GAAP Financial Measures” contains a description of Distributable Cash from Operations and a reconciliation to net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
As reservoir pressures decline, production from a given well or formation decreases. Maintaining or growing our future production and reserves will depend on our ability to continue to replace current production with new reserves. Accordingly, we plan to focus on maintaining reserves through both the drill bit and acquisitions, while maintaining a conservative financial profile. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel, and successfully identify and consummate acquisitions. See “Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry” for a discussion of these and other risks affecting our proved reserves and production.
Commodity Price Changes
Our major market risk exposure is in the pricing that we receive for our oil and natural gas production. Pricing for oil and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil and natural gas production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.
To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil and natural gas production through various transactions that limit the risks of fluctuations of future prices. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. While there is a risk we may not be able to realize the full benefits of rising prices, these hedging activities are intended to limit our exposure to product price volatility and to maintain stable cash flows.
The following table shows estimated Adjusted EBITDAX and Distributable Cash from Operations under various assumed NYMEX-WTI oil and NYMEX-Henry Hub natural gas prices for the twelve months ending June 30, 2025 and for the twelve months ending December 31, 2025. For the twelve months ending June 30, 2025, we have assumed that commodity derivative contracts will cover (i) 371 Mbbl, or approximately 65% of our estimated total oil production from proved reserves for the twelve months ending June 30, 2025, at a weighted average floor price of $66.33 per Bbl and (ii) 1,279 Mcf, or approximately 43% of our estimated total natural gas production from proved reserves for the twelve months ending June 30, 2025, at a weighted average floor price of $3.47 per Mcf. For the twelve months ending December 31, 2025, we have assumed that commodity derivative contracts will cover (i) 325 Mbbl, or approximately 29% of our estimated total oil production from proved reserves for the twelve months ending December 31, 2025, at a weighted average floor price of $65.36 per Bbl and (ii) 1,112 Mcf, or approximately 31% of our estimated total natural gas production from proved reserves for the twelve months ending December 31, 2025, at a weighted average floor price of $3.50 per Mcf. Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas production and reserves. In addition, the estimated Adjusted EBITDAX and Distributable Cash from Operations amounts shown below are based on forecasted realized commodity prices that take into account assumptions based on our average historical NYMEX commodity price differentials as set forth in our December 31, 2023 reserve report. We have assumed no changes in our production based on changes
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in prices. The estimated Adjusted EBITDAX and Distributable Cash from Operations amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions.
| Forecasted Twelve Months Ending June 30, 2025 | Forecasted Twelve Months Ending December 31, 2025 | |||||||||||||||||||||||
| Percentage of Forecasted Prices | Percentage of Forecasted Prices | |||||||||||||||||||||||
| 80% | 100% | 120% | 80% | 100% | 120% | |||||||||||||||||||
| (in thousands, except per unit amounts) | (in thousands, except per unit amounts) | |||||||||||||||||||||||
Forecasted net production(1): | ||||||||||||||||||||||||
Oil (MBbl) | 572 | 572 | 572 | 1,112 | 1,112 | 1,112 | ||||||||||||||||||
Natural gas (Mmcf) | 2,960 | 2,960 | 2,960 | 3,582 | 3,582 | 3,582 | ||||||||||||||||||
Total (Mboe) | 1,065 | 1,065 | 1,065 | 1,709 | 1,709 | 1,709 | ||||||||||||||||||
Oil (Bbl/d) | 1,566 | 1,566 | 1,566 | 3,047 | 3,047 | 3,047 | ||||||||||||||||||
Natural gas (Mcf/d) | 8,108 | 8,108 | 8,108 | 9,814 | 9,814 | 9,814 | ||||||||||||||||||
Total (Boe per day) | 2,918 | 2,918 | 2,918 | 4,683 | 4,683 | 4,683 | ||||||||||||||||||
Forecasted Prices(1): | ||||||||||||||||||||||||
NYMEX-WTI oil price (per Bbl) | 62.64 | 78.30 | 93.96 | 60.10 | 75.13 | 90.16 | ||||||||||||||||||
Realized oil sales price (per Bbl) (excluding derivatives) | 59.97 | 75.63 | 91.29 | 58.10 | 73.13 | 88.16 | ||||||||||||||||||
Realized oil sales price (per Bbl) (including derivatives) | 62.55 | 67.38 | 73.70 | 59.63 | 70.48 | 81.11 | ||||||||||||||||||
NYMEX- Henry Hub natural gas price (per Mcf) | 2.48 | 3.10 | 3.72 | 2.78 | 3.48 | 4.18 | ||||||||||||||||||
Realized natural gas sales price (per Mcf) (excluding derivatives) | 2.18 | 2.80 | 3.42 | 2.48 | 3.18 | 3.88 | ||||||||||||||||||
Realized natural gas sales price (per Mcf) (including derivatives) | 2.62 | 3.03 | 3.37 | 2.71 | 3.22 | 3.74 | ||||||||||||||||||
Estimated Net Income (Loss)(2) | $ | (205 | ) | $ | 2,699 | $ | 5,017 | $ | 6,397 | $ | 15,498 | $ | 24,405 | |||||||||||
Interest expense, net of interest income | 2,629 | 2,629 | 2,629 | 1,179 | 1,179 | 1,179 | ||||||||||||||||||
Income tax provision (benefit) | (54 | ) | 717 | 1,334 | 1,701 | 4,120 | 6,487 | |||||||||||||||||
Depreciation, depletion and amortization | 24,530 | 24,530 | 24,530 | 39,367 | 39,367 | 39,367 | ||||||||||||||||||
Impairment of oil and natural gas properties | — | — | — | — | — | — | ||||||||||||||||||
Accretion | 237 | 237 | 237 | 250 | 250 | 250 | ||||||||||||||||||
Exploration expenses | — | — | — | — | — | — | ||||||||||||||||||
Non-cash gain (loss) on commodity derivatives | — | — | — | — | — | — | ||||||||||||||||||
Non-cash incentive compensation expenses | — | — | — | — | — | — | ||||||||||||||||||
Non-cash (gain) loss on extinguishment of debt | — | — | — | — | — | — | ||||||||||||||||||
Non-cash (gain) loss on investment in PSI | — | — | — | — | — | — | ||||||||||||||||||
Abandonment | — | — | — | — | — | — | ||||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||
Estimated Adjusted EBITDAX(2) | $ | 27,137 | $ | 30,812 | $ | 33,747 | $ | 48,894 | $ | 60,414 | $ | 71,688 | ||||||||||||
Cash interest expense, net of interest income | (2,629 | ) | (2,629 | ) | (2,629 | ) | (1,179 | ) | (1,179 | ) | (1,179 | ) | ||||||||||||
Development costs | (19,911 | ) | (19,911 | ) | (19,911 | ) | (71,056 | ) | (71,056 | ) | (71,056 | ) | ||||||||||||
Acquisition costs | — | — | — | — | — | — | ||||||||||||||||||
Cash income tax payments | — | — | — | — | — | — | ||||||||||||||||||
Reimbursement of general partner expenses | — | — | — | — | — | — | ||||||||||||||||||
Distributable Cash from Operations(3) | $ | 4,597 | $ | 8,272 | $ | 11,207 | $ | (23,341 | ) | $ | (11,821 | ) | $ | (547) | ||||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas production and reserves as well as in the natural gas price. |
| (2) | Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our operating results. “The Offering—Non-GAAP Financial Measures” contains a description of Adjusted EBITDAX and a reconciliation to our net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
| (3) | Distributable Cash from Operations is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. “The Offering—Non-GAAP Financial Measures” contains a description of Distributable Cash from Operations and a reconciliation to net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.
Quarterly Distributions of Available Cash
General
Our partnership agreement requires that, within 90 days after the end of each quarter beginning with the quarter ending , 2024, we distribute all of our Available Cash, if any, to Class A Common Unitholders of record on the applicable record date. We will adjust the amount of our cash distribution for the period from the closing of this offering through , based on the actual length of that period.
Definition of Available Cash
Available Cash generally means, for any quarter:
| • | cash and cash equivalents on hand at the end of that quarter, which, for the avoidance of doubt, includes all proceeds from this offering; |
| • | plus, all cash on hand on the date of determination resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter; |
| • | plus, if our general partner so determines, all or a portion of cash on hand on the date of determination resulting from working capital borrowings made after the end of the quarter; |
| • | less, the amount of cash reserves established by our general partner to: |
| • | provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, future acquisitions, debt service requirements; |
| • | comply with applicable law, any of our debt instruments or other agreements; or |
| • | provide funds for distribution to our Class A Common Unitholders for one or more of the next four quarters. |
The purpose and effect of the first and third bullet points above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of Available Cash for that quarter or proceeds from this offering to pay distributions to Class A Common Unitholders. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.
Methods of Distribution
We intend to distribute Available Cash to our Class A Common Unitholders, pro rata. Our partnership agreement permits, but does not require, us to borrow to pay distributions. Accordingly, there is no guarantee that we will pay the initial target quarterly distribution amount, or any distributions at all, on the Class A Common Units in any quarter.
Operating Surplus and Capital Surplus
General
All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus”. We treat distributions of Available Cash from operating surplus differently than distributions of Available Cash from capital surplus.
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Operating Surplus
Operating surplus for any period generally means:
| • | all of our cash and cash equivalents at the closing of this offering, including, as determined by our general partner, all or a portion of cash receipts from this offering; plus |
| • | all of our cash receipts (including our proportionate share of cash receipts of any subsidiaries we do not wholly own) after the closing of this offering, excluding cash from (1) borrowings, other than working capital borrowings, (2) sales of equity and debt securities, (3) sales or other dispositions of assets outside the ordinary course of business (collectively, clauses (1)-(3), “interim capital transactions”) and (4) PSI Proceeds (as defined below); plus |
| • | working capital borrowings (including our proportionate share of working capital borrowings for any subsidiaries we do not wholly own) made after the end of a quarter but before the date of determination of operating surplus for the quarter as determined by our general partner; less |
| • | all of our “operating expenditures” (which includes maintenance and replacement capital expenditures as further described below) (including our proportionate share of operating expenditures by any subsidiaries we do not wholly own) immediately after the closing of this offering; less |
| • | the amount of cash reserves (including our proportionate share of cash reserves for any subsidiaries we do not wholly own) established by our general partner to provide funds for future operating expenditures. |
As described above, operating surplus includes a provision that will enable us, if we choose, to distribute as operating surplus, any or all of the cash receipts we receive in this offering, which would otherwise be distributed as capital surplus.
Operating expenditures generally means all of our cash expenditures, including but not limited to taxes, reimbursement of expenses to our general partner, debt service payments, and maintenance and estimated replacement capital expenditures (which are discussed in further detail under “—Capital Expenditures” below), provided that operating expenditures will not include:
| • | payments (including prepayments and payment penalties) of principal of and premium on indebtedness required in connection with the sale or other disposition of assets or made in connection with the refinancing or refunding of indebtedness with the proceeds from new indebtedness or from the sale of equity interests; |
| • | expansion capital expenditures, investment capital expenditures or replacement capital expenditures (which are discussed in further detail under “—Capital Expenditures” below); |
| • | payment of transaction expenses (including taxes) relating to interim capital transactions; or |
| • | distributions to partners. |
Capital Expenditures
For purposes of determining operating surplus, capital expenditures are classified as either replacement capital expenditures, expansion capital expenditures or investment capital expenditures. Replacement capital expenditures are those capital expenditures required to maintain, improve or expand, over the long-term, the operating capacity of or the revenue generated by our capital assets.
Expansion capital expenditures are those capital expenditures that increase the operating capacity of or the revenue generated by our capital assets.
Investment capital expenditures are those capital expenditures that are neither replacement capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital
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expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of equity securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes.
Definition of Capital Surplus
Capital surplus generally will be generated only by:
| • | borrowings other than working capital borrowings; |
| • | sales of debt and equity securities; and |
| • | sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or non-current assets sold as part of normal retirements or replacements of assets. |
Characterization of Cash Distributions
We will treat all Available Cash distributed as coming from operating surplus until the sum of all Available Cash distributed since the closing of this offering, other than proceeds from the sale of our investment in PSI, equals the operating surplus as of the most recent date of determination of Available Cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus cash receipts we receive in this offering, that would otherwise be distributed as capital surplus.
Distributions of Available Cash from Operating Surplus
We will make distributions from Available Cash from operating surplus in the following manner:
| • | first, to the Class A Common Unitholders, pro rata, until we distribute for each outstanding Class A Common Unit an amount equal to the initial target quarterly distribution for that quarter; |
| • | second, for distributions above the initial target quarterly distribution for each outstanding Class A Common Unit |
| • | if the quarter occurs prior to the completion of the first six full quarters following the closing of this offering, to the Class A Common Unitholders, pro rata, and |
| • | if the quarter occurs after the completion of the first six full quarters following the closing of this offering, 10% to our general partner and 90% to the Class A Common Unitholders, pro rata. |
Distributions of Available Cash from Capital Surplus
We will make distributions from Available Cash from capital surplus in the following manner:
| • | first, to the Class A Common Unitholders, pro rata, until we distribute for each outstanding Class A Common Unit an amount equal to the excess of the price paid for such Class A Common Unit in this offering over the operating surplus distributions made in respect of such Class A Common Unit for the current and prior quarters; |
| • | second, to the Class B Common Unitholders, pro rata until we distribute for each outstanding Class B Common Unit an amount equal to the value of such Class B Common Unit as of the closing of this offering; and |
| • | third, 10% to our general partner and 90% to the Class A Common Unitholders and Class B Common Unitholders, pro rata and on an as-converted basis, as one class. |
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Distributions of Proceeds from the Sale of our Investment in PSI
We will make distributions of the proceeds of any sale of our investment in PSI (“PSI Proceeds”) in the following manner:
| • | first, to the Class A Common Unitholders and Class B Common Unitholders, pro rata and on an as-converted basis, until we distribute an amount equal to the aggregate value of our investment in PSI as of the closing of this offering; and |
| • | second, 10% to our general partner and 90% to the Class A Common Unitholders and Class B Common Unitholders, pro rata and on an as-converted basis. |
Distributions upon Liquidation
If we sell all or substantially all of our assets or dissolve in accordance with the partnership agreement, in connection with which we would sell or otherwise dispose of our assets in a process called liquidation, we will apply the proceeds in the following manner:
| • | first, to the payment of our creditors in satisfaction of any indebtedness; |
| • | second, to the Class A Common Unitholders, pro rata, until we distribute for each outstanding Class A Common Unit an amount equal to the price paid for such Class A Common Unit in this offering; |
| • | third, to the Class B Common Unitholders, pro rata until we distribute for each outstanding Class B Common Unit an amount equal to the value of such Class B Common Unit as of the closing of this offering; |
| • | fourth, to the Class A Common Unitholders and Class B Common Unitholders, pro rata and on an as-converted basis, as one class, until we have distributed (including all prior distributions) an amount to the Class A Common Unitholders and Class B Common Unitholders equal to the Company’s aggregate equity value as of the closing of this offering; and |
| • | fifth, 10% to our general partner and 90% to the Class A Common Unitholders and Class B Common, pro rata and on an as-converted basis, as one class. |
We cannot assure that there will be sufficient proceeds in liquidation to make any distributions to the Class A Common Unitholders.
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SELECTED PREDECESSOR COMBINED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The selected predecessor combined historical consolidated financial data set forth below as of and for each of the years ended December 31, 2023 and 2022 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The selected predecessor combined historical consolidated financial data set forth below as of June 30, 2024 and for the six months ended June 30, 2024 and 2023 are derived from our unaudited condensed consolidated financial statements and related notes included elsewhere in this prospectus.
The selected unaudited pro forma financial data for the year ended December 31, 2023 are derived from the unaudited pro forma condensed financial statements of Peak Resources LP included elsewhere in this prospectus. The selected unaudited pro forma financial data as of June 30, 2024 and for the six months ended June 30, 2024 are derived from the unaudited pro forma condensed financial statements of Peak Resources LP included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:
| • | the Reorganization Transactions as described in “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Financing Transaction” elsewhere in this prospectus; and |
| • | the issuance and sale by us to the public of Class A Common Units in this offering and the application of the net proceeds of the offering as described in “Use of Proceeds.” |
The unaudited pro forma financial data were prepared as if the items listed above occurred on January 1, 2023, for pro forma statements of operations purposes, and on June 30, 2024, for pro forma balance sheet purposes, with respect to the pro forma financial data as of December 31, 2023 and June 30, 2024, respectively. We have not given pro forma effect to the incremental general and administrative expenses that we expect to incur annually as a result of being a publicly-traded partnership.
The unaudited pro forma historical financial data is presented for illustrative purposes only and is not necessarily indicative of the financial position that would have existed or the financial results that would have occurred if this offering and the Reorganization Transactions had occurred on the dates indicated, nor is it necessarily indicative of the financial position or results of our operations in the future. The pro forma adjustments, as described in the notes to the unaudited pro forma condensed combined financial statements, are preliminary and based upon currently available information and certain assumptions that our management believes are reasonable. The selected historical consolidated financial data is qualified in its entirety by, and should be read in conjunction with, the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section included in this prospectus and the consolidated financial statements and related notes and other financial information included in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed combined financial statements include more detailed information regarding the basis of presentation for the following information. Historical results are not necessarily indicative of results that may be expected for any future period.
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You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our historical combined financial statements and our unaudited pro forma condensed combined financial statements and the notes thereto included elsewhere in this prospectus. Among other things, those historical combined financial statements and the unaudited pro forma condensed combined financial statements include more detailed information regarding the basis of presentation for the following information.
| Predecessor Combined Historical | Pro Forma | |||||||||||||||||||||||
| Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||
| (in thousands, except per unit amounts) | 2024 | 2023 | 2023 | 2022 | ||||||||||||||||||||
Statement of operations information: | ||||||||||||||||||||||||
Revenue: | ||||||||||||||||||||||||
Oil and natural gas sales, net(1) | $ | 24,529 | $ | 27,960 | $ | 54,133 | $ | 94,646 | $ | 24,529 | $ | 54,133 | ||||||||||||
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Total revenue, net | 24,529 | 27,960 | 54,133 | 94,646 | $ | 24,529 | $ | 54,133 | ||||||||||||||||
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Operating Expenses: | ||||||||||||||||||||||||
Lease operating | 6,397 | 6,839 | 13,949 | 14,164 | 6,397 | $ | 13,949 | |||||||||||||||||
Production and ad valorem taxes | 3,266 | 4,043 | 7,508 | 11,393 | 3,266 | $ | 7,508 | |||||||||||||||||
Depletion, depreciation and amortization | 7,163 | 13,275 | 28,801 | 30,917 | 7,163 | $ | 28,801 | |||||||||||||||||
Accretion | 116 | 113 | 227 | 224 | 116 | $ | 227 | |||||||||||||||||
Abandonment | 1,973 | 2,896 | 2,932 | 1,143 | 1,973 | $ | 2,932 | |||||||||||||||||
Impairment of oil and natural gas properties(2) | — | — | 111,871 | — | — | $ | 111,871 | |||||||||||||||||
General and administrative | 4,486 | 4,070 | 7,830 | 7,352 | 4,486 | $ | 7,830 | |||||||||||||||||
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Total operating expenses | 23,401 | 31,236 | 173,118 | 65,193 | 23,401 | $ | 173,118 | |||||||||||||||||
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Income (loss) from operations | 1,128 | (3,276 | ) | (118,985 | ) | 29,453 | 1,128 | $ | (118,985 | ) | ||||||||||||||
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Other Income (Expense): | ||||||||||||||||||||||||
Gain (loss) on commodity derivatives | (6,992 | ) | 3,573 | 1,604 | (27,271 | ) | (6,992 | ) | $ | 1,604 | ||||||||||||||
Interest expense, net | (4,330 | ) | (4,193 | ) | (8,867 | ) | (4,913 | ) | (4,330 | ) | $ | (8,867 | ) | |||||||||||
Loss from retirement of long-term debt | — | (1,089 | ) | (1,080 | ) | — | — | $ | (1,080 | ) | ||||||||||||||
Investment income(3) | — | — | — | — | 2,304 | $ | 9,675 | |||||||||||||||||
Gain (loss) on sale of assets | (23 | ) | 1,203 | 1,240 | 7 | (23 | ) | $ | 1,240 | |||||||||||||||
Other gain (loss) | 90 | 1,293 | 1,652 | (862 | ) | 90 | $ | 1,652 | ||||||||||||||||
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Total other income (expense) | (11,255 | ) | 787 | (5,451 | ) | (33,039 | ) | (8,951 | ) | $ | 4,224 | |||||||||||||
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Net income (loss) before income taxes | (10,127 | ) | (2,489 | ) | (124,436 | ) | (3,586 | ) | (7,823 | ) | (114,761 | ) | ||||||||||||
Income tax benefit (provision) | — | — | — | — | 1,641 | 24,138 | ||||||||||||||||||
Net Loss | $ | (10,127 | ) | $ | (2,489 | ) | $ | (124,436 | ) | $ | (3,586 | ) | $ | (6,182 | ) | $ | (90,623 | ) | ||||||
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| Predecessor Combined Historical | Pro Forma | |||||||||||||||||||||||
| Six Months Ended June 30, | Year Ended December 31, | Six Months Ended June 30, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||
| (in thousands, except per unit amounts) | 2024 | 2023 | 2023 | 2022 | ||||||||||||||||||||
Pro forma information: | ||||||||||||||||||||||||
Pro forma net loss(4) | $ | (10,127 | ) | $ | (2,489 | ) | $ | (124,436 | ) | $ | (3,586 | ) | $ | (6,182 | ) | $ | (90,623 | ) | ||||||
Pro forma net loss per Class A Common Unit | ||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||
Pro forma weighted-average number of Class A Common Units | ||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||
Balance sheet information (end of period): | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 9,170 | $ | 10,468 | $ | 15,439 | $ | 6,561 | $ | 9,170 | $ | 15,439 | ||||||||||||
Total oil and natural gas properties | $ | 187,397 | $ | 312,703 | $ | 194,658 | $ | 317,774 | $ | 187,397 | $ | 194,658 | ||||||||||||
Total assets | $ | 213,454 | $ | 345,368 | $ | 233,985 | $ | 346,926 | $ | 249,851 | $ | 280,979 | ||||||||||||
Long-term debt | $ | 48,610 | $ | 53,957 | $ | 49,765 | $ | 52,000 | $ | 48,610 | $ | 49,765 | ||||||||||||
Total liabilities | $ | 93,023 | $ | 92,864 | $ | 103,427 | $ | 91,932 | $ | 103,337 | $ | 116,314 | ||||||||||||
Total members’ equity | $ | 120,431 | $ | 252,504 | $ | 130,588 | $ | 254,994 | $ | 146,514 | $ | 164,665 | ||||||||||||
Net cash provided by (used by): | ||||||||||||||||||||||||
Operating activities | $ | (2,391 | ) | $ | 4,684 | $ | 14,093 | $ | 20,829 | $ | (2,391 | ) | $ | 23,768 | ||||||||||
Investing activities | $ | (2,248 | ) | $ | (7,733 | ) | $ | (9,099 | ) | $ | (15,278 | ) | $ | (2,248 | ) | $ | (9,099 | ) | ||||||
Financing activities | $ | (1,630 | ) | $ | 6,956 | $ | 3,884 | $ | (19,408 | ) | $ | (1,630 | ) | $ | (3,884 | ) | ||||||||
Other financial information: | ||||||||||||||||||||||||
Adjusted EBITDAX(5) | $ | 10,211 | $ | 12,056 | $ | 24,076 | $ | 29,708 | $ | 10,211 | $ | 33,751 | ||||||||||||
Distributable Cash from Operations(6) | $ | 5,987 | $ | (134 | ) | $ | 5,689 | $ | 11,743 | $ | 5,987 | $ | 15,364 | |||||||||||
| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and revenue. |
| (2) | Impairment for the year ended December 31, 2023 and the twelve months ended June 30, 2024 was primarily due to a decrease in the value of proved oil and natural gas reserves as a result of lower oil and natural gas prices at December 31, 2023 and June 30, 2024, respectively, as well as SEC guidelines on development pace. For the year ended December 31, 2023, oil and natural gas prices calculated in accordance with SEC guidelines decreased by 16.5% and 58.5%, respectively, as compared to the year ended December 31, 2022. |
| (3) | Adjustment to reflect distributions received from PSI representing a return on investment during the six months ended June 30, 2024 and the year ended December 31, 2023. |
| (4) | Pro forma net loss reflects a pro forma income tax benefit of $1.6 million for the six months ended June 30, 2024 and $24.1 million for the year ended December 31, 2023, respectively, all of which is associated with the income tax effects of the corporate reorganization described under “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction” and this offering. Our predecessor was not subject to U.S. federal income tax at an entity level. As a result, the consolidated net loss in our historical financial statements does not reflect the tax expense or benefit we would have incurred if we were subject to U.S. federal income tax at an entity level during such periods. |
| (5) | Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our operating results. “—Non-GAAP Financial Measures” below contains a description of Adjusted EBITDAX and a reconciliation to our net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
| (6) | Distributable Cash from Operations is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. “The Offering—Non-GAAP Financial Measures” contains a description of Distributable Cash from Operations and a reconciliation to net income (loss), our most directly comparable financial measure calculated in accordance with GAAP. |
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the “Selected Predecessor Combined Historical and Pro Forma Financial and Operating Data” and the audited historical financial statements and related notes of Peak E&P and PBLM, as well as the unaudited pro forma financial statements included elsewhere in this prospectus. Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operation” reflects the historical financial results of Peak E&P and PBLM, on an individual basis and does not include the results of, or give pro forma effect to, the offering and the Reorganization Transactions described in “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction.”
The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance, which may affect future operating results and financial position. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Actual results and the timing of the events could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of reserves, capital expenditures, economic, inflationary and competitive conditions, drilling results, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly under “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
We are an independent limited partnership that was recently formed to hold investments in oil and natural gas businesses and assets owned by certain investment partnerships managed by Yorktown, management and other investors who are not affiliated with Yorktown or management. The historical financial statements of Peak Resources LP are not included in this registration statement because it does not currently have any assets or liabilities. We conduct our operating activities in Wyoming. We believe the reservoir quality and stacked pay potential of the Powder River Basin is similar to that of the Permian Basin, with an approximate 4,000-foot gross column, high oil content and significant over-pressure, with multiple productive horizons as deep as 13,500 feet. In addition, the geographic location of the Powder River Basin provides us with attractive realized pricing and operating leverage due to its proximity to end markets, installed infrastructure with ample capacity for growth, access to in-basin service providers and what we view as a favorable regulatory climate in the State of Wyoming for hydrocarbon development operations. Further we expect that with increased basin-wide activity, our production costs will decrease on a per Boe basis while maintaining realized pricing due to ample takeaway and a geographical advantage.
As of June 30, 2024, we had approximately 65,000 gross (45,000 net) acres comprised of private, state, and federal lands with a number of large, contiguous leasehold blocks in the over-pressured core of the Powder River Basin, primarily in Campbell and Converse Counties, Wyoming. We have drilled and operate a total of 104 gross (56 net) producing horizontal wells. In addition, we have drilled two gross (one net) horizontal wells awaiting completion. We also own interests in an additional 83 gross (five net) non-operated, producing horizontal wells with an average working interest of approximately 6.0%. All 83 gross (five net) non-operated wells are operated primarily by other leading Powder River Basin operators including EOG Resources, Devon Energy, Anschutz Exploration, and Ballard Petroleum.
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Factors Affecting the Comparability of Our Future Results of Operations to Our Historical Results of Operations
Our future results of operations may not be comparable to our historical results of operations for the periods presented, primarily for the reasons described below.
Reorganization Transactions—The historical consolidated financial statements included in this prospectus are of Peak E&P and PBLM prior to the Reorganization Transactions described in “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction.” Our historical financial data may not yield an accurate indication of what our actual results would have been if the Reorganization Transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. For our results of operations of Peak E&P and PBLM presented on a combined basis and pro forma for the Reorganization Transactions and this offering, please see “Selected Predecessor Combined Historical and Pro Forma Financial and Operating Data” presented elsewhere in this prospectus.
Public Company Expenses—Upon the completion of this offering, we expect to incur incremental non-recurring costs related to our transition to a publicly traded partnership, including the costs of this initial public offering and the costs associated with the initial implementation of our internal control implementation and testing. We also expect to incur additional recurring costs related to being a public company, including costs associated with the employment of additional personnel, compliance under the Exchange Act and applicable securities exchange requirements, annual and quarterly reports to be filed with the SEC, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, and incremental director and officer liability insurance costs. The direct, incremental general and administrative expenses are not included in our historical or pro forma financial statements; however, we expect those expenses to be approximately $2.5 million per year.
Impairment—We evaluate our producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.
New Credit Facility—Prior to this offering, we intend to negotiate the terms of the New Credit Facility at the Partnership level with prospective lenders that we anticipate entering into after the completion of this offering. The amount, maturity, interest rates and other terms of the New Credit Facility are in the process of being negotiated with prospective lenders; however we expect that the aggregate commitments thereunder will be approximately $150.0 million with an initial borrowing base of $45.0 million. If we are unable to obtain binding commitments for the New Credit Facility on acceptable terms, or at all, the Existing Credit Agreement may remain outstanding after this offering. We may not be able to arrange binding commitments for the New Credit Facility, or the pricing, size, covenants or other terms of the facility may be less favorable than the New Credit Facility described herein, which could increase our interest costs, reduce our operational or financial flexibility, or reduce our access to liquidity.
Tax Status—Even though we are organized as a partnership under state law, we made an election to be treated as a corporation for United States federal income tax purposes. As such, we are subject to income tax at
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the United States federal corporate tax rate. The amount of taxable income attributable to non-controlling interest is not subject to federal income taxes. Prior to this offering, we were not subject to United States federal income taxes as we were organized and taxed as partnerships.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our operations, including the following sources of our revenue, principal components of our cost structure and other financial metrics:
| • | production volumes; |
| • | realized prices on the sale of oil and natural gas; |
| • | lease operating expenses; |
| • | Adjusted EBITDAX; and |
| • | Distributable Cash from Operations. |
Net Production Volumes—Our oil and natural gas revenue is derived from the sale of oil and natural gas production. We report our reserves in two streams: oil and natural gas. The economic value of NGLs is included in our natural gas price and production. As reservoir pressures decline, production from a given well or formation decreases. Growth in future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions.
Realized Prices—The NYMEX WTI and Henry Hub futures prices are widely used benchmarks in the pricing of domestic and imported oil and natural gas, respectively, in the United States. The actual prices realized from the sale of oil and natural gas differ from the quoted NYMEX WTI price and the NYMEX Henry Hub price, respectively, as a result of quality and location differentials. The prices we realize on the oil produced is affected by the ability to transport crude oil to the applicable transportation hub. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the proximity of the natural gas to the major consuming markets to which it is ultimately delivered.
We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations and to satisfy the requirement under Peak E&P’s Existing Credit Agreement (as defined herein) to hedge, on a rolling quarterly basis, reasonably anticipated projected production of proved developed producing reserves. All derivative instruments are recorded on the consolidated balance sheets as an asset or liability measured at fair value, with changes in the fair value of the derivatives recorded currently in the consolidated statements of operations. For the years ended December 31, 2023 and 2022, and for the six months ended June 30, 2024 and 2023, we did not designate any of our derivative contracts as cash flow hedges. PBLM does not engage in hedging activities.
Hedging only provides partial price protection against declines in prices and may partially limit our potential gains from future price increases. In addition, in times of low commodity prices, our ability to enter into additional commodity derivative contracts with favorable commodity price terms may be limited, which may adversely impact our future operating income and cash flows as compared to historical periods during which we were able to hedge a portion of production at higher prices.
Principal Components of Our Cost Structure
Lease Operating Expense—Lease operating expenses are the costs incurred in the operation and maintenance of producing properties and related well workover expenses. Expenses for direct labor, water
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injection and disposal, utilities, materials, supplies, compressor rental, and surface-use payments comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production or ad valorem taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to equipment or surface facilities result in increased lease operating expenses in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, certain power and water disposal costs may vary directly with the amount of hydrocarbons and water produced.
We monitor our operations to ensure we are incurring lease operating expenses at an acceptable level. Although we strive to reduce our lease operating expenses, these expenses can increase or decrease on a per unit basis as a result of various factors.
Production and Ad Valorem Tax Expense—Production taxes are paid based on a percentage of revenues from oil and natural gas production sold at fixed rates established by state or local taxing authorities. In general, the production taxes we pay are correlated to changes in revenues. We recognize and pay production taxes at the full statutory rate until an application for a reduced production tax rate is approved, as applicable, at which time a refund will be issued for severance taxes paid in excess of the approved reduced rate. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties and vary slightly across the different counties in which we operate.
Depletion, Depreciation and Amortization—Depletion, depreciation and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas and oil. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with the drilling and completion of oil and natural gas properties associated with developmental wells. Costs associated with exploratory wells are capitalized, or suspended, until we determine if proved reserves are discovered.
Accretion—We recognize accretion expense in connection with the discounted liability for future abandonment costs over the remaining estimated economic lives of the respective oil and natural gas properties.
Abandonment—We recognize abandonment expenses in connection with the determination that certain leases of unproved property will be allowed to expire. Upon determination that a property lease will be allowed to expire, we recognize an abandonment expense for the associated costs of the lease.
Impairment of Oil and Natural Gas Properties—We review and evaluate our long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax reserve cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. An impairment loss is measured as the amount by which asset carrying value exceeds fair value on an individual field-by-field basis.
General and Administrative—General and administrative expenses include costs incurred to operate the business that are not directly tied to the operation of producing properties. Employee compensation and benefits, rent, office expenses and audit and other fees for professional services and legal compliance comprise the most significant portion of general and administrative expenses.
We monitor our general and administrative expenses to ensure that we are incurring expenses at an acceptable level. Although we strive to reduce our expenses, these expenses can increase or decrease as a result of various factors as we manage our business activities or make acquisitions and dispositions of properties. For
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example, we may increase general and administrative expenses to optimize our business monitoring and reporting, incurring higher expenses in one quarter relative to another or we may acquire or dispose of properties that have different development opportunities. These initiatives would influence our overall general and administrative expenses and could cause fluctuations when comparing general and administrative expenses on a period-to-period basis.
Gain (Loss) on Commodity Derivatives—We recognize our derivative instruments on the consolidated balance sheet as assets or liabilities at fair value with such amounts classified as current or long-term based on anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. We have not designated derivative instruments as hedges for accounting purposes and, as a result, mark derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in our consolidated statements of operations.
Interest Expense, Net—We have borrowings outstanding under our Existing Credit Facility. As a result, we incur interest expense that is impacted by both fluctuations in interest rates and total principal amount outstanding. Interest paid to the lenders under the Existing Credit Facility is included in interest expense in the consolidated statements of operations.
Adjusted EBITDAX—We include in this prospectus the non-GAAP financial measure Adjusted EBITDAX and provide our calculation of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss), our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDAX as net income (loss) before (1) interest expense, net of interest income, (2) income tax provision, (3) depreciation, depletion and amortization, (4) impairment expenses, (5) accretion of discount on asset retirement obligations, (6) exploration expenses, (7) unrealized (gains) losses on commodity derivative contracts, (8) non-cash incentive compensation, (9) non-cash (gain) loss on investment in PSI, (10) abandonment expenses, and (11) certain other non-cash expenses. For a reconciliation of Adjusted EBITDAX to net income (loss), our most directly comparable financial measures calculated and presented in accordance with GAAP, see “The Offering—Non-GAAP Financial Measures—Adjusted EBITDAX.”
We believe Adjusted EBITDAX is useful because it allows us 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 exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX 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. Adjusted EBITDAX 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. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies.
Distributable Cash from Operations—Distributable Cash from Operations is not a measure of net cash flow provided by or used in operating activities as determined by GAAP. Distributable Cash from Operations is a supplemental non-GAAP financial measure used by our management and by external users of our financial statements, such as investors, lenders and others (including industry analysts and rating agencies who will be using such measure), to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define Distributable Cash from Operations as Adjusted EBITDAX, including dividends, less (1) cash interest expense, net of interest income, (2) development costs net of divestiture proceeds, (3) acquisition costs, (4) cash income tax payments, (5) reimbursements of expenses and payment of fees to our general partner and its affiliates and (6) certain other cash expenses. Development costs include all of our capital expenditures made for oil and natural gas properties, other than acquisitions, net of any
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proceeds from divestitures. Distributable Cash from Operations will not reflect changes in working capital balances. Distributable Cash from Operations is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measure most directly comparable to Distributable Cash from Operations is net income (loss). Distributable Cash from Operations should not be considered as an alternative to, or more meaningful than, net income (loss).
Results of Operations—Peak E&P
Six Months Ended June 30, 2024 Compared to the Six Months Ended June 30, 2023
Revenues
The following information provides the components of Peak E&P’s revenues, as well as average realized prices and net production volumes (dollar amounts in thousands):
| Six Months Ended June 30, | 2024 Compared to 2023 | |||||||||||||||
| 2024 | 2023 | Change | % Change | |||||||||||||
Revenues: | ||||||||||||||||
Oil sales | $ | 20,611 | $ | 21,678 | $ | (1,067 | ) | (4.9 | )% | |||||||
Natural gas sales(1) | 2,366 | 3,587 | (1,221 | ) | (34.0 | )% | ||||||||||
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Total revenues, net | $ | 22,977 | $ | 25,265 | $ | (2,288 | ) | (9.1 | )% | |||||||
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Average Sales Price: | ||||||||||||||||
Oil, without realized derivatives ($/Bbl) | $ | 76.53 | $ | 73.87 | $ | 2.65 | 3.6 | % | ||||||||
Oil, with realized derivatives ($/Bbl) | $ | 71.96 | $ | 67.07 | $ | 4.89 | 7.3 | % | ||||||||
Natural gas, without realized derivatives ($/Mcf) | $ | 1.98 | $ | 2.70 | $ | (0.71 | ) | (26.4 | )% | |||||||
Natural gas, with realized derivatives ($/Mcf) | $ | 2.82 | $ | 2.42 | $ | 0.39 | 16.3 | % | ||||||||
Total, without realized derivatives ($/Boe) | $ | 49.07 | $ | 49.04 | $ | 0.04 | 0.1 | % | ||||||||
Total, with realized derivatives ($/Boe) | $ | 48.57 | $ | 44.46 | $ | 4.12 | 9.3 | % | ||||||||
Net Production Volumes: | ||||||||||||||||
Oil (Bbls) | 269,332 | 293,448 | (24,116 | ) | (8.2 | )% | ||||||||||
Natural gas (Mcf) | 1,193,367 | 1,330,748 | (137,381 | ) | (10.3 | )% | ||||||||||
Total (Boe) | 468,227 | 515,239 | (47,013 | ) | (9.1 | )% | ||||||||||
Average daily production (Boe/d) | 2,573 | 2,847 | (274 | ) | (9.6 | )% | ||||||||||
| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and production. |
Peak E&P’s results of operations are heavily influenced by commodity prices, which have historically been volatile. As Peak E&P’s production consists primarily of oil, its revenues are more sensitive to fluctuations in oil prices, as compared to fluctuations in natural gas prices. An extended decline in commodity prices may adversely affect Peak E&P’s business, financial condition or results of operations and its ability to meet capital expenditure obligations and financial commitments.
The following table provides the dollar effect of changes in commodity prices on Peak E&P’s oil and natural gas revenues for the periods indicated (dollar amounts in thousands):
| Six Months Ended June 30, 2024 Compared to 2023 | ||||||||||||
| Change in Price | Production Volumes | Total Net Effect | ||||||||||
Effect of Change in Price: | ||||||||||||
Oil sales (Bbls) | $ | 2.65 | 269,332 | $ | 715 | |||||||
Natural gas sales (Mcf)(1) | $ | (0.71 | ) | 1,193,367 | (851 | ) | ||||||
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Change in total revenues | $ | (136 | ) | |||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and production. |
The following table provides the dollar effect of changes in production volumes on Peak E&P’s oil and natural gas revenues for the periods indicated (dollar amounts in thousands):
| Six Months Ended June 30, 2024 Compared to 2023 | ||||||||||||
| Change in Production | Prior Period Prices | Total Net Effect | ||||||||||
Effect of Change in Production: | ||||||||||||
Oil sales (Bbls) | (24,116 | ) | $ | 73.87 | $ | (1,782 | ) | |||||
Natural gas sales (Mcf)(1) | (137,381 | ) | $ | 2.70 | (370 | ) | ||||||
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Change in total revenues | $ | (2,152 | ) | |||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and production. |
Production decreased 47,013 Boe, or 9.1%, for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. This decrease in production was primarily due to natural production decline with oil and natural gas production decreasing by 8.2% and 10.3%, respectively, during the six months ended June 30, 2024, as compared to the six months ended June 30, 2023.
Operating Expenses
The following information provides the components of Peak E&P’s operating expenses, on both an absolute basis and per Boe basis, (dollar amounts in thousands):
| Six Months Ended June 30, | 2024 Compared to 2023 | |||||||||||||||
| 2024 | 2023 | Change | % Change | |||||||||||||
Operating Expenses: | ||||||||||||||||
Lease operating | $ | 6,050 | $ | 6,506 | $ | (456 | ) | (7.0 | )% | |||||||
Production and ad valorem taxes | 3,057 | 3,678 | (621 | ) | (16.9 | )% | ||||||||||
Depletion, depreciation and amortization | $ | 6,555 | 12,139 | (5,584 | ) | (46.0 | )% | |||||||||
Accretion | 114 | 111 | 3 | 2.7 | % | |||||||||||
Abandonment | 1,921 | 2,863 | (942 | ) | (32.9 | )% | ||||||||||
General and administrative | 3,606 | 3,436 | 170 | 4.9 | % | |||||||||||
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Total operating expenses | $ | 21,303 | $ | 28,733 | $ | (7,430 | ) | (25.9 | )% | |||||||
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Operating Expenses ($/BOE): |
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Lease operating | $ | 12.92 | $ | 12.63 | $ | 0.29 | 2.3 | % | ||||||||
Production and ad valorem taxes | $ | 6.53 | $ | 7.14 | $ | (0.61 | ) | (8.5 | )% | |||||||
Depletion, depreciation and amortization | $ | 14.00 | $ | 23.56 | $ | (9.56 | ) | (40.6 | )% | |||||||
Accretion | $ | 0.24 | $ | 0.22 | $ | 0.02 | 9.1 | % | ||||||||
Abandonment | $ | 4.10 | $ | 5.56 | $ | (1.45 | ) | (26.2 | )% | |||||||
General and administrative | $ | 7.70 | $ | 6.67 | $ | 1.03 | 15.5 | % | ||||||||
Lease Operating—Lease operating expenses decreased by 7.0%, to $6.1 million for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. On a Boe basis, lease operating expenses increased by 2.3% to $12.92 per Boe as a result of lower production during the six months ended June 30, 2024 as compared to the six months ended June 30, 2023.
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Production and Ad Valorem Taxes—Production and ad valorem taxes decreased by 16.9%, to $3.1 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. On a Boe basis, production and ad valorem taxes decreased by 8.5% to $6.53 per Boe for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. Lower production and ad valorem taxes per Boe were the result of lower natural gas prices during the six months ended June 30, 2024, as compared to the six months ended June 30, 2023.
Depletion, Depreciation and Amortization—Depletion, depreciation and amortization expenses decreased by 46.0%, to $6.6 million for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. On a Boe basis, depletion, depreciation and amortization expenses decreased by 40.6% to $14.00 per Boe for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. Lower depletion, depreciation and amortization expenses were the result of a significant decrease in the net book value of proved oil and gas properties at June 30, 2024, as compared to June 30, 2023, due to a large impairment charge booked at the end of 2023, offset partially by lower overall production for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023.
Abandonment—Abandonment expenses were $1.9 million for the six months ended June 30, 2024, as compared to $2.9 million for the six months ended June 30, 2023. Peak E&P performs a periodic review of unproved property costs to determine (i) whether any leases associated with the property have expired or been abandoned, (ii) whether the subject property will be developed or (iii) if the carrying value of the property is not realizable.
General and Administrative—General and administrative expenses increased by 4.9%, to $3.6 million for the six months ended June 30, 2024, as compared to six months ended June 30, 2023. Higher general and administrative expenses were primarily the result of market adjustments to compensation. On a Boe basis, general and administrative expenses increased by 15.5% to $7.70 per Boe for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. Higher general and administrative expenses per Boe were the result of a decrease in overall production, slightly offset by increase in general and administrative expenses due to market adjustments to compensation for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023.
Other Income (Expense)
The following information provides the components of Peak E&P’s other income and expenses (in thousands):
| Six Months Ended June 30, | 2024 Compared to 2023 | |||||||||||||||
| 2024 | 2023 | Change | % Change | |||||||||||||
Other Income (Expense): | ||||||||||||||||
Gain (loss) on commodity derivatives | $ | (6,992 | ) | $ | 3,573 | $ | (10,565 | ) | (295.7 | )% | ||||||
Interest expense, net | (4,330 | ) | (4,193 | ) | (137 | ) | 3.3 | % | ||||||||
Loss from retirement of long-term debt | — | (1,089 | ) | 1,089 | * | |||||||||||
Gain (loss) on sale of assets | (23 | ) | 1,203 | (1,226 | ) | (101.9 | )% | |||||||||
Other gain | 52 | 1,293 | (1,241 | ) | (96.0 | )% | ||||||||||
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Total other income (expense) | $ | (11,293 | ) | $ | 787 | $ | (12,080 | ) | * | |||||||
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| * | Percentage change not meaningful |
Gain (Loss) on Commodity Derivatives—Gain (loss) on commodity derivatives decreased to a loss of $7.0 million for the six months ended June 30, 2024, as compared to a gain of $3.6 million for the six months ended June 30, 2023.
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The following table provides the components of Peak E&P’s gain (loss) on commodity derivatives for the six months ended June 30, 2024 and 2023:
| Six Months Ended June 30, | 2024 Compared to 2023 | |||||||||||||||
| 2024 | 2023 | Change | % Change | |||||||||||||
Cash paid on derivatives | $ | (236 | ) | $ | (2,359 | ) | $ | 2,124 | (90.0 | )% | ||||||
Non-cash gain (loss) on derivatives | (6,756 | ) | 5,932 | (12,689 | ) | (213.9 | )% | |||||||||
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Gain (loss) on commodity derivatives | $ | (6,992 | ) | $ | 3,573 | $ | (10,565 | ) | (295.7 | )% | ||||||
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The $2.1 million favorable change in cash paid on derivatives was largely driven by lower oil and natural gas prices for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023.
Interest Expense, Net—Interest expense, net, increased by 3.3%, to $4.3 million, for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. The increase in interest expense for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023, was due to a slightly higher interest rate associated with the Existing Credit Agreement (as compared to the prior credit facilities), which was a weighted average of 13.48% for the six months ended June 30, 2024, as compared to a weighted average of 12.63% for the six months ended June 30, 2023.
Loss From Retirement of Long-Term Debt—Loss from retirement of long-term debt was $1.1 million for the six months ended June 30, 2023. During the six months ended June 30, 2023, Peak E&P entered into the Existing Credit Agreement and used the proceeds to fully repay the Prior Credit Facility and the NPA (as hereinafter defined). As a result of the full repayment of the Prior Credit Facility and NPA, all unamortized debt issuance costs associated with those two facilities were written off, resulting in a loss from the early retirement of those two facilities.
Year Ended December 31, 2023 Compared to the Year Ended December 31, 2022
Revenues
The following information provides the components of Peak E&P’s revenues, as well as average realized prices and net production volumes (dollar amounts in thousands):
| Year Ended December 31, | 2023 Compared to 2022 | |||||||||||||||
| 2023 | 2022 | Change | % Change | |||||||||||||
Revenues: | ||||||||||||||||
Oil sales | $ | 43,553 | $ | 66,236 | $ | (22,683 | ) | (34.2 | )% | |||||||
Natural gas sales(1) | 6,078 | 18,365 | (12,287 | ) | (66.9 | )% | ||||||||||
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Total revenues, net | $ | 49,631 | $ | 84,601 | $ | (34,970 | ) | (41.3 | )% | |||||||
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Average Sales Price: | ||||||||||||||||
Oil, without realized derivatives ($/Bbl) | $ | 76.17 | $ | 93.25 | $ | (17.08 | ) | (18.3 | )% | |||||||
Oil, with realized derivatives ($/Bbl) | $ | 69.70 | $ | 62.26 | $ | 7.44 | 11.9 | % | ||||||||
Natural gas, without realized derivatives ($/Mcf)(1) | $ | 2.45 | $ | 6.37 | $ | (3.92 | ) | (61.5 | )% | |||||||
Natural gas, with realized derivatives ($/Mcf)(1) | $ | 2.46 | $ | 3.19 | $ | (0.73 | ) | (22.9 | )% | |||||||
Total, without realized derivatives ($/Boe) | $ | 50.35 | $ | 71.06 | $ | (20.71 | ) | (29.1 | )% | |||||||
Total, with realized derivatives ($/Boe) | $ | 46.63 | $ | 44.87 | $ | 1.76 | 3.9 | % | ||||||||
Net Production Volumes: |
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Oil (Bbls) | 571,769 | 710,294 | (138,525 | ) | (19.5 | )% | ||||||||||
Natural gas (Mcf) | 2,484,069 | 2,881,933 | (397,864 | ) | (13.8 | )% | ||||||||||
Total (Boe) | 985,781 | 1,190,616 | (204,835 | ) | (17.2 | )% | ||||||||||
Average daily production (Boe/d) | 2,701 | 3,262 | (561 | ) | (17.2 | )% | ||||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and production. |
Peak E&P’s results of operations are heavily influenced by commodity prices, which have historically been volatile. As Peak E&P’s production consists primarily of oil, its revenues are more sensitive to fluctuations in oil prices, as compared to fluctuations in natural gas prices. An extended decline in commodity prices may adversely affect Peak E&P’s business, financial condition or results of operations and its ability to meet capital expenditure obligations and financial commitments.
The following table provides the dollar effect of changes in commodity prices on Peak E&P’s oil and natural gas revenues for the periods indicated (dollar amounts in thousands):
| Year Ended December 31, 2023 Compared to 2022 | ||||||||||||
| Change in Prices | Production Volumes | Total Net Effect | ||||||||||
Effect of Change in Price: |
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Oil sales (Bbls) | $ | (17.08 | ) | 571,769 | $ | (9,766 | ) | |||||
Natural gas sales (Mcf)(1) | $ | (3.92 | ) | 2,484,069 | (9,738 | ) | ||||||
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Change in total revenues | $ | (19,504 | ) | |||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and sales. |
The following table provides the dollar effect of changes in production volumes on Peak E&P’s oil and natural gas revenues for the periods indicated (dollar amounts in thousands):
| Year Ended December 31, 2023 Compared to 2022 | ||||||||||||
| Change in Production Volumes | Prior Period Prices | Total Net Effect | ||||||||||
Effect of Change in Production: |
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Oil sales (Bbls) | (138,525 | ) | $ | 93.25 | $ | (12,917 | ) | |||||
Natural gas sales (Mcf)(1) | (397,864 | ) | $ | 6.37 | (2,549 | ) | ||||||
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Change in total revenues | $ | (15,466 | ) | |||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our pricing and natural gas production. |
Production decreased 204,835 Boe, or 17.2%, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. This decrease in production was attributable to lower oil production, which decreased by 19.5%, and lower natural gas production, which decreased by 13.8%, both during the year ended December 31, 2023 as compared to the year ended December 31, 2022.
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Operating Expenses
The following information provides the components of Peak E&P’s operating expenses, on both an absolute basis and per Boe basis, (dollar amounts in thousands):
| Year Ended December 31, | 2023 Compared to 2022 | |||||||||||||||
| 2023 | 2022 | Change | % Change | |||||||||||||
Operating Expenses: | ||||||||||||||||
Lease operating | $ | 13,243 | $ | 13,436 | $ | (193 | ) | (1.4 | )% | |||||||
Production and ad valorem taxes | 6,943 | 10,182 | (3,239 | ) | (31.8 | )% | ||||||||||
Depletion, depreciation and amortization | 27,061 | 28,687 | (1,626 | ) | (5.7 | )% | ||||||||||
Accretion | 223 | 220 | 3 | 1.4 | % | |||||||||||
Abandonment | 2,882 | 1,092 | 1,790 | 163.9 | % | |||||||||||
Impairment of oil and natural gas properties | 111,871 | — | 111,871 | * | ||||||||||||
General and administrative | 6,566 | 6,049 | 517 | 8.5 | % | |||||||||||
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Total operating expenses | $ | 168,789 | $ | 59,666 | $ | 109,123 | 182.9 | % | ||||||||
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Operating Expenses ($/Boe): | ||||||||||||||||
Lease operating | $ | 13.43 | $ | 11.28 | $ | 2.15 | 19.1 | % | ||||||||
Production and ad valorem taxes | $ | 7.04 | $ | 8.55 | $ | (1.51 | ) | (17.7 | )% | |||||||
Depletion, depreciation and amortization | $ | 27.45 | $ | 24.09 | $ | 3.36 | 13.9 | % | ||||||||
Accretion | $ | 0.23 | $ | 0.18 | $ | 0.05 | 27.8 | % | ||||||||
Abandonment | $ | 2.92 | $ | 0.92 | $ | 2.00 | 217.4 | % | ||||||||
Impairment of oil and natural gas properties | $ | 113.48 | $ | — | $ | 113.48 | * | |||||||||
General and administrative | $ | 6.65 | $ | 5.08 | $ | 1.57 | 30.9 | % | ||||||||
| * | Percentage change not meaningful |
Lease Operating—Lease operating expenses decreased by 1.4%, to $13.2 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. On a Boe basis, lease operating expenses increased by 19.1%, to $13.43 per Boe, as a result of lower production during the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Production and Ad Valorem Taxes—Production and ad valorem taxes decreased by 31.8%, to $6.9 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. On a Boe basis, production and ad valorem taxes decreased by 17.7%, to $7.04 per Boe, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. Lower production and ad valorem taxes were the result of lower realized pricing, as Peak E&P’s realized pricing for oil, without realized derivatives, decreased by 18.3% and realized pricing for natural gas, without realized derivatives, decreased by 61.5% for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Depletion, Depreciation and Amortization—Depletion, depreciation and amortization expenses decreased by 5.7%, to $27.1 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. On a Boe basis, depletion, depreciation and amortization expenses increased by 13.9%, to $27.45 per Boe, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. Higher depletion, depreciation and amortization expenses on a Boe basis were the result of a decrease in proved oil and gas reserves for the 2023 year and offset partially by lower overall production for the year ended December 31, 2023, as compared to the year ended December 31, 2022. Additionally, declines in prices led to a reduction in PUD reserves as of December 31, 2023 due to reserves becoming uneconomical at lower prices and shorter lives.
Abandonment—Abandonment expenses increased by 163.9%, to $2.9 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. Peak E&P performs a periodic review of
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unproved property costs to determine (i) whether any leases associated with the property have expired or been abandoned, (ii) whether the subject property will be developed, or (iii) if the carrying value of the property is not realizable. To conserve cash, certain leases associated with unproved property were allowed to expire, resulting in an increase in abandonment expense for the year ended December 31, 2023.
Impairment of Oil and Natural Gas Properties—For the year ended December 31, 2023, Peak E&P recorded an impairment of oil and natural gas properties of $111.9 million. This impairment was primarily due to a decrease in the value of proved oil and natural gas reserves as a result of lower oil and natural gas prices at December 31, 2023. For purposes of determining proved reserves, under guidelines established by the SEC, estimates of proved oil and natural gas reserves are prepared using existing economic and operating conditions and oil and natural gas prices based upon the 12-month unweighted average first day of the month spot prices. For the year ended December 31, 2023, oil and natural gas prices calculated in accordance with SEC guidelines decreased by 16.5% and 58.5%, respectively, as compared to the year ended December 31, 2022.
General and Administrative—General and administrative expenses increased by 8.5%, to $6.6 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. Higher general and administrative expenses were primarily the result of market adjustments to compensation. On a Boe basis, general and administrative expenses increased by 30.9%, to $6.65 per Boe, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. Higher general and administrative expenses per Boe were the result of a decrease in production as well as market adjustments to compensation for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Other Income (Expense)
The following information provides the components of Peak E&P’s other income and expenses (in thousands):
| Year Ended December 31, | 2023 Compared to 2022 | |||||||||||||||
| 2023 | 2022 | Change | % Change | |||||||||||||
Other Income (Expense): | ||||||||||||||||
Gain (loss) on commodity derivatives | $ | 1,604 | $ | (27,271 | ) | $ | 28,875 | 105.9 | % | |||||||
Interest expense, net | (8,867 | ) | (4,913 | ) | (3,954 | ) | (80.5 | )% | ||||||||
Loss from retirement of long-term debt | (1,080 | ) | — | (1,080 | ) | * | ||||||||||
Gain on sale of assets | 1,240 | 7 | 1,233 | * | ||||||||||||
Other gain (loss) | 1,619 | (887 | ) | 2,506 | * | |||||||||||
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Total other expense | $ | (5,484 | ) | $ | (33,064 | ) | $ | 27,580 | 83.4 | % | ||||||
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| * | Percentage change not meaningful |
Gain (Loss) on Commodity Derivatives—Gain (loss) on commodity derivatives increased to a gain of $1.6 million for the year ended December 31, 2023, from a loss of $27.3 million for the year ended December 31, 2022.
The following table provides the components of Peak E&P’s gain (loss) on commodity derivatives for the years ended December 31, 2023 and 2022:
| Year Ended December 31, | 2023 Compared to 2022 | |||||||||||||||
| 2023 | 2022 | Change | % Change | |||||||||||||
Cash paid on derivatives | $ | (3,662 | ) | $ | (31,174 | ) | $ | 27,512 | 88.3 | % | ||||||
Non-cash gain on derivatives | 5,266 | 3,903 | 1,363 | 34.9 | % | |||||||||||
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Gain (loss) on commodity derivatives | $ | 1,604 | $ | (27,271 | ) | $ | 28,875 | 105.9 | % | |||||||
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The $27.5 million favorable change in cash paid on derivatives was largely driven by lower oil and natural gas prices for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Interest Expense, Net—Interest expense, net, increased by 80.5%, to $8.9 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase in interest expense for the 2023 year was due to a $6.9 million increase in borrowings under the Existing Credit Agreement, along with a higher interest rate associated with the Existing Credit Agreement (as compared to the prior credit facilities), which was a weighted average of 13.07% for the year ended December 31, 2023, as compared to a weighted average of 7.82% for the year ended December 31, 2022.
Loss From Retirement of Long-Term Debt—Loss from retirement of long-term debt was $1.1 million for the year ended December 31, 2023. During the year ended December 31, 2023, Peak E&P entered into the Existing Credit Agreement and used the proceeds to fully repay the Prior Credit Facility and the NPA (each as defined below). As a result of the full repayment of the Prior Credit Facility and NPA, all unamortized debt issuance costs associated with those two facilities were written off, resulting in a loss from the early retirement of those two facilities.
Six Months Ended June 30, 2024 Compared to the Six Months Ended June 30, 2023
Revenues
The following information provides the components of PBLM’s revenues, as well as average realized prices and net production volumes (dollar amounts in thousands):
| Six Months Ended June 30, | 2024 Compared to 2023 | |||||||||||||||
| 2024 | 2023 | Change | % Change | |||||||||||||
Revenues: |
| |||||||||||||||
Oil sales | $ | 1,410 | $ | 2,325 | $ | (915 | ) | (39.3 | )% | |||||||
Natural gas sales(1) | 142 | 370 | (228 | ) | (61.6 | )% | ||||||||||
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Total revenues, net | $ | 1,552 | $ | 2,695 | $ | (1,143 | ) | (42.4 | )% | |||||||
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Average Sales Price: | ||||||||||||||||
Oil ($/Bbl) | $ | 75.36 | $ | 72.13 | $ | 3.23 | 4.5 | % | ||||||||
Natural gas ($/Mcf) | $ | 1.87 | $ | 2.64 | $ | (0.77 | ) | (29.3 | )% | |||||||
Total ($/Boe) | $ | 49.45 | $ | 48.47 | $ | 0.98 | 2.0 | % | ||||||||
Net Production Volumes: | ||||||||||||||||
Oil (Bbls) | 18,709 | 32,233 | (13,524 | ) | (42.0 | )% | ||||||||||
Natural gas (Mcf) | 76,067 | 140,211 | (64,144 | ) | (45.7 | )% | ||||||||||
Total (Boe) | 31,387 | 55,302 | (24,215 | ) | (43.6 | )% | ||||||||||
Average daily production (Boe/d) | 172 | 307 | (135 | ) | (43.9 | )% | ||||||||||
| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and production. |
PBLM’s results of operations are heavily influenced by commodity prices, which have historically been volatile. As PBLM’s production consists primarily of oil, its revenues are more sensitive to fluctuations in oil prices, as compared to fluctuations in natural gas prices. An extended decline in commodity prices may adversely affect PBLM’s business, financial condition or results of operations and its ability to meet capital expenditure obligations and financial commitments.
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The following table provides the dollar effect of changes in commodity prices on PBLM’s oil and natural gas revenues for the periods indicated (dollar amounts in thousands):
| Six Months Ended June 30, 2024 Compared to 2023 | ||||||||||||
| Change in Price | Production Volumes | Total Net Effect | ||||||||||
Effect of Change in Price: |
| |||||||||||
Oil sales (Bbls) | $ | 3.23 | 18,709 | $ | 61 | |||||||
Natural gas sales (Mcf)(1) | $ | (0.77 | ) | 76,067 | (59 | ) | ||||||
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Change in total revenues | $ | 2 | ||||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and production. |
The following table provides the dollar effect of changes in production volumes on PBLM’s oil and natural gas revenues for the periods indicated (dollar amounts in thousands):
| Six Months Ended June 30, 2024 Compared to 2023 | ||||||||||||
| Change in Production | Prior Period Prices | Total Net Effect | ||||||||||
Effect of Change in Production: |
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Oil sales (Bbls) | (13,524 | ) | $ | 72.13 | $ | (976 | ) | |||||
Natural gas sales (Mcf)(1) | (64,144 | ) | $ | 2.64 | (169 | ) | ||||||
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Change in total revenues | $ | (1,145 | ) | |||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and production. |
Production decreased 24,215 Boe, or 43.6%, for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. This decrease in production was due to higher initial production declines from the four wells that began producing in January 2023.
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Operating Expenses
The following information provides the components of PBLM’s operating expenses, on both an absolute basis and per Boe basis, (dollar amounts in thousands):
| Six Months Ended June 30, | 2024 Compared to 2023 | |||||||||||||||
| 2024 | 2023 | Change | % Change | |||||||||||||
Operating Expenses: | ||||||||||||||||
Lease operating | $ | 347 | $ | 333 | $ | 14 | 4.2 | % | ||||||||
Production and ad valorem taxes | 209 | 365 | (156 | ) | (42.7 | )% | ||||||||||
Depletion, depreciation and amortization | 608 | 1,136 | (528 | ) | (46.5 | )% | ||||||||||
Accretion | 2 | 2 | — | — | ||||||||||||
Abandonment | 52 | 33 | 19 | 57.6 | % | |||||||||||
General and administrative | 880 | 634 | 246 | 38.8 | % | |||||||||||
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Total operating expenses | $ | 2,098 | $ | 2,503 | $ | (405 | ) | (16.2 | )% | |||||||
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Operating Expenses ($/BOE): | ||||||||||||||||
Lease operating | $ | 11.06 | $ | 5.99 | $ | 5.07 | 84.6 | % | ||||||||
Production and ad valorem taxes | $ | 6.66 | $ | 6.56 | $ | (0.09 | ) | 1.4 | % | |||||||
Depletion, depreciation and amortization | $ | 19.37 | $ | 20.43 | $ | (1.06 | ) | (5.2 | )% | |||||||
Accretion | $ | 0.06 | $ | 0.04 | $ | 0.02 | 50.0 | % | ||||||||
Abandonment | $ | 1.66 | $ | 0.59 | $ | 1.07 | 181.4 | % | ||||||||
General and administrative | $ | 28.04 | $ | 11.40 | $ | 16.63 | 145.9 | % | ||||||||
Lease Operating — Lease operating expenses increased by 4.2%, to $0.3 million for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. On a Boe basis, lease operating expenses increased by 84.6% to $11.06 per Boe as a result of lower oil and natural gas production during the six months ended June 30, 2024, as compared to the six months ended June 30, 2023, as a result of the higher initial production from the four wells that began producing in January 2023
Production and Ad Valorem Taxes — Production and ad valorem taxes decreased by 42.7%, to $0.2 million for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. On a Boe basis, production and ad valorem tax decreased by 1.4% to $6.66 per Boe for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023 as a result of the higher initial production from the four wells that began producing in January 2023.
Depletion, Depreciation and Amortization — Depletion, depreciation and amortization expenses remained consistent with a slight decrease of 46.5%, to $0.6 million for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. On a Boe basis, depletion, depreciation and amortization expenses decreased by 5.2% to $19.37 per Boe for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. Higher depletion, depreciation and amortization expenses on a Boe basis were the result of lower oil and natural gas production for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023.
General and Administrative — General and administrative expenses increased by 38.8%, to $0.9 million for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. On a Boe basis, general and administrative expenses increased by 145.9% to $28.04 per Boe for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. Higher general and administrative expenses per Boe were the result of lower production for the six months ended June 30, 2024, as compared to the six months ended June 30, 2023. PBLM is subject to an administrative services agreement (“ASA”) with Peak E&P, an affiliate, that specifies that Peak E&P will perform administrative duties associated with PBLM’s properties. Per the ASA, PBLM is required to pay Peak E&P approximately $0.1 million monthly. For the six months ended June 30,
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2024, PBLM did not pay Peak E&P any ASA fees as the ASA fees for the six months ended June 30, 2024, were prepaid in December 2023. For the six months ended June 30, 2023, PBLM paid Peak E&P $0.6 million. We anticipate that the ASA will be terminated upon the consummation of the Reorganization Transactions.
Year Ended December 31, 2023 Compared to the Year Ended December 31, 2022
Revenues
The following information provides the components of PBLM’s revenues, as well as average realized prices and net production volumes (dollar amounts in thousands):
| Year Ended December 31, | 2023 Compared to 2022 | |||||||||||||||
| 2023 | 2022 | Change | % Change | |||||||||||||
Revenues: |
| |||||||||||||||
Oil sales | $ | 3,964 | $ | 9,204 | $ | (5,240 | ) | (56.9 | )% | |||||||
Natural gas sales(1) | 538 | 841 | (303 | ) | (36.0 | )% | ||||||||||
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Total revenues, net | $ | 4,502 | $ | 10,045 | $ | (5,543 | ) | (55.2 | )% | |||||||
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Average Sales Price: | ||||||||||||||||
Oil ($/Bbl) | $ | 74.66 | $ | 93.45 | $ | (18.79 | ) | (20.1 | )% | |||||||
Natural gas ($/Mcf)(1) | $ | 2.44 | $ | 8.40 | $ | (5.96 | ) | (71.0 | )% | |||||||
Total ($/Boe) | $ | 50.08 | $ | 87.21 | $ | (37.13 | ) | (42.6 | )% | |||||||
Net Production Volumes: | ||||||||||||||||
Oil (Bbls) | 53,094 | 98,498 | (45,404 | ) | (46.1 | )% | ||||||||||
Natural gas (Mcf)(1) | 220,736 | 100,126 | 120,610 | 120.5 | % | |||||||||||
Total (Boe) | 89,883 | 115,186 | (25,303 | ) | (22.0 | )% | ||||||||||
Average daily production (Boe/d) | 246 | 316 | (70 | ) | (22.2 | )% | ||||||||||
| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing, revenues and production. |
PBLM’s results of operations are heavily influenced by commodity prices, which have historically been volatile. As PBLM’s production consists primarily of oil, its revenues are more sensitive to fluctuations in oil prices, as compared to fluctuations in natural gas prices. An extended decline in commodity prices may adversely affect PBLM’s business, financial condition or results of operations and its ability to meet capital expenditure obligations and financial commitments.
The following table provides the dollar effect of changes in commodity prices on PBLM’s oil and natural gas revenues for the periods indicated (dollar amounts in thousands):
| Year Ended December 31, 2023 Compared to 2022 | ||||||||||||
| Change in Prices | Production Volumes | Total Net Effect | ||||||||||
Effect of Change in Price: |
| |||||||||||
Oil sales (Bbls) | $ | (18.79 | ) | 53,094 | $ | (998 | ) | |||||
Natural gas sales (Mcf)(1) | $ | (5.96 | ) | 220,736 | (1,316 | ) | ||||||
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Change in total revenues | $ | (2,314 | ) | |||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and sales. |
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The following table provides the dollar effect of changes in production volumes on PBLM’s oil and natural gas revenues for the periods indicated (dollar amounts in thousands):
| Year Ended December 31, 2023 Compared to 2022 | ||||||||||||
| Change in Production Volumes | Prior Period Prices | Total Net Effect | ||||||||||
Effect of Change in Production: |
| |||||||||||
Oil sales (Bbls) | (45,404 | ) | $ | 93.45 | $ | (4,242 | ) | |||||
Natural gas sales (Mcf)(1) | 120,610 | $ | 8.40 | 1,013 | ||||||||
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Change in total revenues | $ | (3,229 | ) | |||||||||
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| (1) | Because our reserves and production are reported in two streams, the economic value of the NGLs is included in our natural gas pricing and sales. |
Production decreased 25,303 Boe, or 22.0%, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. This decrease in production was primarily attributable to lower oil production, which decreased by 46.1% during the year ended December 31, 2023, as compared to the year ended December 31, 2022. During the year ended December 31, 2023, PBLM participated in four wells with significant GORs. As a result, PBLM’s share of natural gas production increased significantly during the year ended December 31, 2023, while its share of oil production was not significant enough to offset natural oil decline from wells put into production during the year ended December 31, 2022.
Operating Expenses
The following information provides the components of PBLM’s operating expenses, on both an absolute basis and per Boe basis (dollar amounts in thousands):
| Year Ended December 31, | 2023 Compared to 2022 | |||||||||||||||
| 2023 | 2022 | Change | % Change | |||||||||||||
Operating Expenses: | ||||||||||||||||
Lease operating | $ | 706 | $ | 728 | $ | (22 | ) | (3.0 | )% | |||||||
Production and ad valorem taxes | 565 | 1,211 | (646 | ) | (53.3 | )% | ||||||||||
Depletion, depreciation and amortization | 1,740 | 2,230 | (490 | ) | (22.0 | )% | ||||||||||
Accretion | 4 | 4 | — | — | ||||||||||||
Abandonment | 50 | 51 | (1 | ) | (2.0 | )% | ||||||||||
General and administrative | 1,264 | 1,303 | (39 | ) | (3.0 | )% | ||||||||||
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Total operating expenses | $ | 4,329 | $ | 5,527 | $ | (1,198 | ) | (21.7 | %) | |||||||
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Operating Expenses ($/Boe): | ||||||||||||||||
Lease operating | $ | 7.85 | $ | 6.32 | $ | 1.53 | 24.2 | % | ||||||||
Production and ad valorem taxes | $ | 6.29 | $ | 10.51 | $ | (4.22 | ) | (40.2 | )% | |||||||
Depletion, depreciation and amortization | $ | 19.36 | $ | 19.36 | — | — | ||||||||||
Accretion | $ | 0.04 | $ | 0.04 | — | — | ||||||||||
Abandonment | $ | 0.56 | $ | 0.44 | $ | 0.12 | 27.3 | % | ||||||||
General and administrative | $ | 14.06 | $ | 11.31 | $ | 2.75 | 24.3 | % | ||||||||
Lease Operating—Lease operating expenses decreased by 3.0%, to $0.7 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. On a Boe basis, lease operating expenses increased by 24.2%, to $7.85 per Boe, as a result of lower oil production during the year ended December 31, 2023, as compared to the year ended December 31, 2022.
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Production and Ad Valorem Taxes—Production and ad valorem taxes decreased by 53.3%, to $0.6 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. On a Boe basis, production and ad valorem taxes decreased by 40.2%, to $6.29 per Boe, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. Lower production and ad valorem taxes were the result of lower realized pricing, as PBLM’s realized pricing for oil decreased by 20.1% and realized pricing for natural gas decreased by 71.0% for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Depletion, Depreciation and Amortization—Depletion, depreciation and amortization expenses decreased by 22.0%, to $1.7 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. On a Boe basis, depletion, depreciation and amortization expenses were consistent at $19.36 per Boe, for the year ended December 31, 2023 and the year ended December 31, 2022. Lower depletion, depreciation and amortization expenses were the result of lower oil production for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
General and Administrative—General and administrative expenses decreased by 3.0%, to $1.3 million, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. On a Boe basis, general and administrative expenses increased by 24.3%, to $14.06 per Boe, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. Higher general and administrative expenses per Boe were the result of lower production for the year ended December 31, 2023, as compared to the year ended December 31, 2022. PBLM is subject to an administrative services agreement (the “ASA”) with Peak E&P, an affiliate, that specifies that Peak E&P will perform administrative duties associated with PBLM’s properties. Per the ASA, PBLM is required to pay Peak E&P approximately $0.1 million monthly. For the years ended December 31, 2023 and 2022, PBLM paid Peak E&P $1.2 million each year. We anticipate that the ASA will be terminated upon the consummation of the Reorganization Transactions.
Liquidity and Capital Resources
As a publicly-traded partnership, our primary sources of liquidity and capital resources will be from cash flow generated by operating activities and proceeds from this offering. Historically, our primary sources of liquidity have also included cash from our Existing Owners, but we do not expect to rely on our Existing Owners for capital following the completion of this offering. We may need to utilize the public equity or debt markets and bank financings to fund future acquisitions or capital expenditures, but the price at which our Class A Common Units will trade could be diminished as a result of the limited voting rights of such holders. We expect to be able to issue additional equity and debt securities from time to time as market conditions allow to facilitate future acquisitions. We expect to repay any debt incurred by us to complete such acquisitions in order to meet our long-term goal of remaining substantially debt free and funding our development plan with our cash flow from operating activities. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations or to refinance our indebtedness will depend on our ability to generate cash in the future. Additionally, rising interest rates can and have impacted our interest expense on our indebtedness. While such rising interest rates historically have not materially impacted our liquidity, continued increases in interest rates will impact our Distributable Cash from Operations. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.
Our partnership agreement requires us to distribute all of our Available Cash. We define “Available Cash” as our cash on hand at the end of each quarter, plus certain distributions or dividends received after the end of the quarter, plus certain working capital borrowings and proceeds from this offering if determined by our general partner, less cash reserves established by our general partner for the proper conduct of our business, such as for capital expenditures, acquisitions, debt service, compliance with law and loan agreements and future distributions. To the extent there is no Available Cash, our partnership agreement does not require us to pay distributions on our Class A Common Units on a quarterly basis or otherwise.
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Our business plan has focused on developing and acquiring high quality acreage within the Powder River Basin. Peak E&P spent approximately $9.3 million in 2023 on development costs. PBLM spent approximately $1.3 million in 2023 on development costs. Our capital budgets for 2024 and 2025 are approximately $7.1 million and $69.8 million, respectively.
Our 2024 and 2025 capital expenditures programs are largely discretionary and within our control. The ultimate amount of our 2024 and 2025 capital expenditures will depend upon a variety of factors, including, but not limited to, the success of operated partners drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions and drilling and acquisition cost.
Based upon current oil and natural price expectations for 2024, we believe that our cash flows from operations and proceeds from this offering will be sufficient to fund our operations through 2024 and into 2025. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. We cannot assure you that operations and other needed capital will be available on acceptable terms or at all.
Cash Flows—Peak E&P
The following table summarizes Peak E&P’s cash flows for the periods indicated (in thousands):
| Six Months Ended June 30, | Year Ended December 31, | |||||||||||||||
| 2024 | 2023 | 2023 | 2022 | |||||||||||||
Net cash provided by (used in): | ||||||||||||||||
Operating activities | $ | (3,210 | ) | $ | 4,900 | $ | 13,814 | $ | 16,981 | |||||||
Investing activities | 1,177 | (6,535 | ) | (7,876 | ) | (11,166 | ) | |||||||||
Financing activities | (1,630 | ) | 6,956 | 3,884 | (19,408 | ) | ||||||||||
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Net increase (decrease) in cash and cash equivalents | $ | (3,663 | ) | $ | 5,321 | $ | 9,822 | $ | (13,593 | ) | ||||||
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Operating Activities—Cash used in operating activities was $3.2 million for the six months ended June 30, 2024, as compared to cash provided by operating activities of $4.9 million for the six months ended June 30, 2023. The decrease in operating cash flows was primarily related to lower revenues of $2.3 million and an unfavorable working capital change of $7.6 million, partially offset by lower settlements of commodity derivatives of $2.1 million.
Cash provided by operating activities was $13.8 million for the year ended December 31, 2023, as compared to $17.0 million for the year ended December 31, 2022. The decrease in operating cash flows was primarily related to lower revenues of $35.0 million, partially offset by lower settlements of commodity derivatives of $27.5 million, a reduction in production and ad valorem taxes of $3.2 million and a decrease in changes to working capital of $1.0 million.
Investing Activities—Cash flow provided by investing activities was $1.2 million for the six months ended June 30, 2024, as compared to cash used in investing activities of $6.5 million for the six months ended June 30, 2023. Additions to oil and natural gas properties accounted for the majority of Peak E&P’s investing activities for the six months ended June 30, 2024 and 2023. Additionally, proceeds from sales of other assets increased to $3.2 million for the six months ended June 30, 2024.
Cash used in investing activities was $7.9 million for the year ended December 31, 2023, as compared to $11.2 million for the year ended December 31, 2022. Additions to oil and natural gas properties accounted for the majority of Peak E&P’s investing activities for the years ended December 31, 2023 and 2022.
Financing Activities—Cash used in financing activities was $1.6 million for the six months ended June 30, 2024, as compared to cash provided by financing activities of $7.0 million for the six months ended June 30,
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2023. Cash used in financing activities for the six months ended June 30, 2024, was primarily associated with Peak E&P’s quarterly principal payment on the Credit and Guaranty Agreement with Fortress Credit Corp. Cash provided by financing activities for the six months ended June 30, 2023 were associated with new borrowings from Peak E&P’s Existing Credit Agreement of $62.0 million, offset partially by full repayment of the Prior Credit Facility and the NPA of $52.0 million, payments on the Existing Credit Agreement of $3.1 million and debt issuance costs of $3.0 million.
Cash provided by financing activities was $3.9 million for the year ended December 31, 2023, as compared to cash used in financing activities of $19.4 million for the year ended December 31, 2022. Cash provided by financing activities for the year ended December 31, 2023 were associated with new borrowings from Peak E&P’s Existing Credit Agreement of $62.0 million, offset partially by full repayment of the Prior Credit Facility and the NPA of $52.0 million, payments on the Existing Credit Agreement of $3.1 million and debt issuance costs of $3.0 million.
Cash Flows—PBLM
The following table summarizes PBLM’s cash flows for the periods indicated (in thousands):
| Six Months Ended June 30, | Year Ended December 31, | |||||||||||||||
| 2024 | 2023 | 2023 | 2022 | |||||||||||||
Net cash provided by (used in): | ||||||||||||||||
Operating activities | $ | 819 | $ | (216 | ) | $ | 279 | $ | 3,848 | |||||||
Investing activities | (3,425 | ) | (1,198 | ) | (1,223 | ) | (4,112 | ) | ||||||||
Financing activities | — | — | — | — | ||||||||||||
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Net decrease in cash and cash equivalents | $ | (2,606 | ) | $ | (1,414 | ) | $ | (944 | ) | $ | (264 | ) | ||||
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Operating Activities—Cash provided by operating activities was $0.8 million for the six months ended June 30, 2024, as compared to cash used in operating activities of $0.2 million for the six months ended June 30, 2023. The increase in operating cash flows was primarily related an increase in working capital of $2.3 million partially offset by lower revenues of $1.1 million.
Cash provided by operating activities was $0.3 million for the year ended December 31, 2023, as compared to $3.8 million for the year ended December 31, 2022. The decrease in operating cash flows was primarily related to lower revenues of $5.5 million, partially offset by a decrease in production and ad valorem taxes of $0.7 million and a decrease in changes to working capital of $1.3 million.
Investing Activities—Cash used in investing activities was $3.4 million for the six months ended June 30, 2024, as compared to $1.2 million for the six months ended June 30, 2023. Additions to oil and natural gas properties accounted for the majority of Peak BLM’s investing activities for the six months ended June 30, 2024 and 2023.
Cash used in investing activities was $1.2 million for the year ended December 31, 2023, as compared to $4.1 million for the year ended December 31, 2022. Additions to oil and natural gas properties accounted for the PBLM’s investing activities for the years ended December 31, 2023 and 2022.
Existing Credit Agreement—In January 2023, Peak E&P entered into a Credit and Guaranty Agreement with Fortress Credit Corp. with initial loan commitments of $62.0 million provided by Fortress Credit Corp. and Cargill, Incorporated (collectively, the “Lenders”). Upon execution of the Existing Credit Agreement, Peak E&P was issued a new term loan with the Lenders for the full commitment amount of $62.0 million, which matures on
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January 31, 2027 (the “Maturity Date”). Proceeds from the new loan were utilized to repay in full the Prior Credit Facility and the NPA (each, as defined below), as well as debt issuance costs. The remaining unused proceeds served as additional cash to Peak E&P’s consolidated balance sheet.
The obligations under the Existing Credit Agreement are guaranteed by certain of Peak E&P’s subsidiaries (the “Guarantors”) and the Existing Credit Agreement is secured by substantially all of the assets owned by Peak E&P and the Guarantors (subject to customary exceptions). Borrowings outstanding under the Existing Credit Agreement are initially Term SOFR Loans (as defined in the Existing Credit Agreement), which bear interest at a rate equal to the sum of (i) the Term SOFR Rate for a three-month interest period, plus 0.15% (“Adjusted Term SOFR Rate”); and (ii) 8.00% per annum. The Administrative Agent (permitted only as expressly set forth in Section 2.07 of the Existing Credit Agreement), may convert any outstanding Term SOFR Loan to an ABR Loan (as defined in the Existing Credit Agreement). Borrowings constituting ABR Loans bear interest at a rate equal to the sum of (i) the Alternate Base Rate, defined as the greater of (a) the Prime Rate and (b) the NYFRB Rate plus 0.50%; and (ii) 7.00% per annum. Interest accrued on all outstanding loans is payable at the end of each quarter, through the Maturity Date.
Peak E&P is required to repay to the Lenders an amount equal to 2.50% of the aggregate principal amount of the outstanding loans, including accrued interest, on the last day of each quarter (or 10% on an annualized basis). Furthermore, Peak E&P is subject to mandatory repayment provisions, including in the event of default where the Lenders elect to accelerate amounts due. The Existing Credit Agreement further outlines the ability to prepay the loans in whole, or in part, at the option of Peak E&P. In the event of any repayment or prepayment of the loans, Peak E&P is required to immediately pay the applicable premium and all accrued interest.
The Existing Credit Agreement contains restrictive covenants that limit Peak E&P’s ability to, among other things: (i) incur additional indebtedness; (ii) incur liens; (iii) enter into mergers; (iv) dispose of assets; (v) engage in new business type; (vi) make any investments; (vii) enter into certain swap agreements; (viii) make restrictive payments; and (ix) engage in certain transactions with affiliates. These restrictive covenants are subject to a number of important exceptions and qualifications.
In addition, the Existing Credit Agreement requires Peak E&P to maintain compliance with the following financial ratios determined as of the last day of the quarter: (A) a current ratio (as defined in the Existing Credit Agreement) of no less than 1.00 to 1.00; (B) a PDP asset coverage ratio (as defined in the Credit Agreement) of no less than 1.75 to 1.00; (C) a leverage ratio (as defined in the Existing Credit Agreement) of no more than 2.75 to 1.00; and (D) liquidity (as defined in the Existing Credit Agreement) of not less than $5.0 million. Furthermore, for any year, general and administrative expenses (as defined in the Existing Credit Agreement) attributable to Peak E&P must not exceed $8.5 million. As of December 31, 2023, Peak E&P did not meet the current ratio requirement and subsequently received a waiver related to non-compliance with the current ratio for such period. Additionally, in April 2024, Peak E&P entered into the first amendment to the Existing Credit Agreement, which provides that the required quarterly principal and interest payments will now be due the first business day of the immediately succeeding quarter, instead of on the last day of the current quarter. Additionally, this amendment provides us with the ability to deduct accrued interest from the calculation of current liabilities. As of June 30, 2024, Peak E&P was in compliance with all covenants outlined above.
PBLM does not have any debt agreements in place.
Wells Fargo Credit Facility—In June 2019, Peak E&P entered into the third amended and restated credit agreement with Wells Fargo Bank, NA for a Senior Secured Revolving Credit Facility (as amended, the “Prior Credit Facility”). The Prior Credit Facility was due May 2023, and bore interest at 2.85% as of December 31, 2022. Peak E&P recorded interest expense of $0.8 million for the six months ended June 30, 2023. The Prior Credit Facility was repaid in full in January 2023 by the Existing Credit Agreement, as discussed above.
Senior Secured Second Lien—In November 2018, Peak E&P entered into a Senior Secured Second Lien Note Purchase Agreement (the “NPA”) with Allianz Global Investors GMBH and other lenders, with US Bank,
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NA acting as the administrative agent. The NPA matured on November 16, 2023, and bore interest at a rate of LIBOR plus 6.75% rate, which averaged 9.00% for the six months ended June 30, 2023. For the six months ended June 30, 2023, Peak E&P recorded interest expense of $4.1 million for the NPA. The NPA was repaid in full in January 2023 by the Existing Credit Agreement, as discussed above.
Our significant contractual obligations are primarily associated with debt, interest expense, asset retirement obligations and commodity derivatives. We believe that our cash on hand and cash flows from operations will be adequate to fund our short and long-term contractual obligations.
Quantitative and Qualitative Disclosure About Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates, as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses.
Oil and Natural Gas Sales—Our revenue and cash flows from operations are subject to many variables, the most significant of which is the volatility of commodity prices. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by global economic factors, pipeline capacity constraints, inventory levels, basis differentials, weather conditions and many other factors. Commodity prices have long been volatile and unpredictable, and we expect this volatility to continue in the future.
There can be no assurance that commodity prices will not be subject to continued wide fluctuations in the future. A substantial or extended decline in prices could have a material adverse effect on our financial position, results of operations, ability to meet our financing commitments and fund planned capital expenditures and distributions.
Commodity Derivatives—As required under our Existing Credit Agreement and in order to reduce the impact of fluctuations of commodity prices on our total revenue and other operating income, we have historically used, and expect to continue to use, commodity derivative instruments, primarily swaps and collars, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in commodity prices and provide increased certainty of cash flows for funding our drilling program and debt service requirements. Commodity derivatives provide only partial price protection against declines in prices and may partially limit our potential gains from future increases in prices. We do not enter derivative contracts for speculative trading purposes.
Each swap transaction has an established fixed price. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract volume. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the contract volume.
Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, we receive an amount from our counterparty equal to the difference between the settlement price and the price floor multiplied by the contract volume. When the settlement price is above the price ceiling established by these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract volume. No payment is received or paid if the settlement price is above the floor price and below the ceiling price.
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We had the following outstanding commodity derivative financial instruments outstanding at June 30, 2024:
| Year Ended December 31, | ||||||||||||||||||||
| 2024 | 2025 | 2026 | 2027 | 2028 | ||||||||||||||||
Natural gas swaps: | ||||||||||||||||||||
Notional volume (MMBtu) | 538,587 | 859,686 | 563,780 | 284,726 | 14,136 | |||||||||||||||
Weighted average swap price ($/MMBtu) | $ | 3.59 | $ | 3.63 | $ | 3.62 | $ | 3.71 | $ | 4.50 | ||||||||||
Natural gas collars: | ||||||||||||||||||||
Notional volume (MMBtu) | 117,650 | 202,145 | 257,281 | 227,389 | 14,136 | |||||||||||||||
Weighted average ceiling price ($/MMBtu) | $ | 4.13 | $ | 4.16 | $ | 4.27 | $ | 4.22 | $ | 4.30 | ||||||||||
Weighted average floor price ($/MMBtu) | $ | 3.12 | $ | 3.17 | $ | 3.28 | $ | 3.19 | $ | 3.20 | ||||||||||
Oil swaps: | ||||||||||||||||||||
Notional volume (Bbl) | 129,413 | 299,678 | 202,539 | 97,675 | 4,464 | |||||||||||||||
Weighted average swap price ($/Bbl) | $ | 69.44 | $ | 65.65 | $ | 63.25 | $ | 64.06 | $ | 64.40 | ||||||||||
Oil collars: | ||||||||||||||||||||
Notional volume (Bbl) | 71,369 | 22,286 | 50,956 | 63,040 | 4,464 | |||||||||||||||
Weighted average ceiling price ($/Bbl) | $ | 74.24 | $ | 72.00 | $ | 69.16 | $ | 67.91 | $ | 69.00 | ||||||||||
Weighted average floor price ($/Bbl) | $ | 64.21 | $ | 62.24 | $ | 59.33 | $ | 57.73 | $ | 58.50 | ||||||||||
Counterparty and Customer Credit Risk—By using derivative instruments to hedge exposures to changes in commodity prices, we are exposed to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of a contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We believe our counterparties currently represent acceptable credit risks. We are not required to provide credit support or collateral to our counterparties under current contracts, nor are the counterparties required to provide credit support or collateral to us.
Substantially all of our revenue and receivables result from oil and natural gas sales to third parties operating in the oil and natural gas industry. Our receivables also include amounts owed by joint interest owners in the properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be affected by changes in commodity prices and economic and other conditions. In the case of joint interest owners, we often have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings.
Interest Rate Risk
Variable Rate Debt—At June 30, 2024, we had $57.4 million of debt outstanding under our Existing Credit Agreement. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate on our variable interest debt would be approximately $0.6 million per year based on our borrowings outstanding at June 30, 2024.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. The accounting estimates and assumptions we consider to be the most significant to the financial statements are discussed below.
Oil and Natural Gas Accounting—We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities, which requires management’s assessment of the proper designation of wells and associated costs as developmental or exploratory.
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Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, we review the status of all suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, we consider current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program. If we determine future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of operations. Otherwise, the costs of exploratory wells remain capitalized. For the years ended December 31, 2023 and 2022, we had no suspended exploratory wells costs.
Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. For each of the years ended December 31, 2023 and 2022, we allowed certain undeveloped acreage to expire, resulting in abandonment expense as reported in the consolidated statements of operations.
Oil and Natural Gas Reserves—Our estimates of proved and proved developed reserves are a major component of our depletion calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of proved reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. These forecasts rely heavily on historical experience of production results, incurred capital costs, operating expenses and workover experience, among other factors.
The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Third-party petroleum engineers prepare our reserve estimates.
Recently Issued Accounting Pronouncements
A summary of recent accounting pronouncements and our assessment of any expected impact of these pronouncements if known is included in notes to the audited consolidated financial statements of Peak E&P and PBLM included elsewhere in this prospectus.
Internal Controls and Procedures
We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report to be filed with the SEC. We have elected to avail ourselves of the provision of the JOBS Act that permits emerging growth companies to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act.
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We are an independent limited partnership that was recently formed to hold investments in oil and natural gas businesses and assets owned by certain investment partnerships managed by Yorktown, management and other investors who are not affiliated with Yorktown or management. Our objective is to consistently create significant equity value for our Class A Common Unitholders in two ways: first, to actively develop and expand our large acreage position in the Powder River Basin of Wyoming in a way that materially increases oil and associated natural gas production, cash flow, and reserve value; and second, to return cash to Class A Common Unitholders through a quarterly distribution of Available Cash.
Our primary operational focus is on using advanced horizontal drilling and completion technology to economically and expeditiously grow our oil and natural gas production and reserves in the Powder River Basin, which we believe remains less developed from a horizontal drilling perspective than most other basins in the United States. We are focused on increasing equity value through the development of our 1,770 gross (530 net) identified horizontal drilling locations. We seek to organically grow our production profile through the low-risk development of our existing properties, funded by cash flow from operating activities and a portion of the net proceeds of this offering. We also believe that the Powder River Basin offers opportunities to make future accretive acquisitions of producing properties and acreage. We expect such acquisitions, together with our development activities, will allow us to further increase our production, reserves and free cash flow, and over time, increase distributions to our unitholders.
We are offering Class A Common Units in this offering. The Class A Common Units will entitle holders of our Class A Common Units to quarterly distributions of Available Cash. Our partnership agreement requires us to distribute all of our Available Cash. We define “Available Cash” as our cash on hand at the end of each quarter, plus certain distributions or dividends received after the end of the quarter, plus certain working capital borrowings and proceeds from this offering if determined by our general partner, less cash reserves established by our general partner, including for the proper conduct of our business, such as for capital expenditures, acquisitions, debt service, compliance with law and loan agreements and future distributions. We intend to make quarterly distributions of Available Cash on our Class A Common Units. Our goal is to make a distribution of at least $ per Class A Common Unit per quarter (adjusted for the number of days in the first quarterly period after the closing date of this offering), which we refer to as our initial target quarterly distribution. However, to the extent there is no Available Cash, our partnership agreement does not require us to pay distributions on our Class A Common Units on a quarterly basis or otherwise.
Our goal is to make consistent quarterly distributions to our Class A Common Unitholders at or above our initial target quarterly distribution that grow over time, based on the attractive economics associated with our development locations and our large multi-year inventory of operated locations. Additionally, we believe our balance sheet strength following this offering, our accretive acquisition opportunities and our expected supplemental dividends from PSI will help us grow our distributions over time. However, we have no legal obligation to pay cash distributions to our Class A Common Unitholders, and there is no guarantee that we will make quarterly cash distributions to our Class A Common Unitholders at the initial target quarterly distribution amount, or at all, or that distributions will grow over time. The amount of cash flow from operations available for distribution with respect to any quarter will be dependent on the then-prevailing prices of oil and natural gas, among other factors. To mitigate the risk associated with volatile commodity prices and to satisfy the requirement under our Existing Credit Agreement (as hereinafter defined), we will hedge, on a rolling quarterly basis, a portion of our production volumes based on reasonably anticipated projected production of proved developed producing reserves that we are required to hedge. To the extent our Distributable Cash from Operations (as hereinafter defined) is insufficient to pay our quarterly distributions, we may use cash on hand, including proceeds from this offering initially designated as reserves, to maintain or grow our cash distributions to our Class A Common Unitholders. See “The Offering—Non-GAAP Financial Measures—Distributable Cash from Operations” for our definition of Distributable Cash from Operations. For example, on a pro forma basis, if
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we had completed the transactions contemplated in this prospectus on January 1, 2023, our pro forma Distributable Cash from Operations would have been approximately $15.4 million for the year ended December 31, 2023 and $14.5 million for the twelve months ended June 30, 2024, which would have been sufficient to pay our initial target quarterly distributions for the quarters in those periods. Additionally, our forecasted Distributable Cash from Operations for the twelve months ending June 30, 2025 is expected to be approximately $8.3 million, which would be sufficient to pay our initial target quarterly distributions for the quarters in that period. However, our forecasted Distributable Cash from Operations for the twelve months ending December 31, 2025 would be insufficient to pay our initial target quarterly distributions for quarters in that period, so all or a portion of the quarterly cash distributions to our Class A Common Unitholders would need to be made from our cash on hand, including from proceeds from this offering initially designated as reserves.
Peak E&P was formed by our management team and investment partnerships managed by Yorktown in 2011 to identify, evaluate, acquire and develop onshore oil and natural gas assets in the United States. Peak E&P is led by Jack E. Vaughn, Glen E. Christiansen and Justin M. Vaughn, who have over 90 years of collective experience operating in the exploration and production industry.
PBLM was formed by an investment partnership managed by Yorktown in 2017 to identify and fund the acquisition of additional high-quality acreage in the Powder River Basin for development by Peak E&P.
Our management team has an established track record of identifying, developing and efficiently operating oil and natural gas assets in the Powder River Basin as well as other premier onshore U.S. basins. Moreover, members of our management team were key participants in the early implementation of advanced drilling techniques in the Granite Wash (Anadarko Basin) as well as the shift from vertical to horizontal drilling and the application of advanced completion techniques in the Barnett Shale (Fort Worth Basin) and Bakken Shale (Williston Basin). In total, our Chief Executive Officer and Yorktown have worked together to navigate three prior successful upstream exits, with an average return on investment of 296%, excluding general and administrative and other expenses. We believe our management team’s experience provides us with a competitive advantage in the identification of opportunities in the Powder River Basin and continues to drive our top-tier operational performance; however, the prior performance of companies or business initiatives in which our management team or Yorktown were involved may not be indicative of our future performance.
Upon completion of this offering, our management team will consist of Jack E. Vaughn, Chief Executive Officer; Ali A. Kouros, Executive Vice President, Corporate Development and Strategy; Glen E. Christiansen, President and Chief Operating Officer; and Justin M. Vaughn, Executive Vice President and Chief Financial Officer. Our management team will be supported by employees, including geologists, completion and drilling engineers, land personnel, regulatory and environmental specialists, as well as field operating personnel.
Powder River Basin, Wyoming, USA
Our primary operational focus is on using advanced horizontal drilling and completion technology to economically and expeditiously grow our oil and natural gas production and proved reserves in the Powder River Basin. We believe that the geologic characteristics and in-place resources of the Powder River Basin make it one of the most attractive regions in the United States for the development and production of oil and associated natural gas. The Powder River Basin consists of an expansive and thick gross column with multiple, proven productive horizons that are conducive to the application of horizontal drilling and completion techniques using state-of-the-art technology. We believe this results in high oil and natural gas recoveries and attractive economic returns relative to drilling and completion costs, lower drilling risk, high initial production rates and long reserve life. Further, we believe at this current development stage, the Powder River Basin remains less developed from a horizontal drilling perspective, which presents many years of attractive development opportunities.
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Utilizing their experience in identifying unconventional resource development opportunities, our management team analyzed the geologic potential of numerous North American basins and decided to make the Powder River Basin our focal point. The Powder River Basin has a long history of oil and natural gas development through the vertical development of its extensive oil reservoirs, and later through the development of its coal bed methane reserves. Like the Permian Basin, the Powder River Basin has been substantially delineated through the drilling of more than 33,000 vertical oil and natural gas wells. However, in our opinion, unlike the Permian Basin, the Powder River Basin’s tight oil resource has yet to be widely re-developed with advanced horizontal drilling and completion technologies.
We believe the reservoir quality and stacked pay potential of the Powder River Basin is similar to that of the Permian Basin, with an approximate 4,000-foot gross column, high oil content and significant over-pressure, with multiple productive horizons as deep as 13,500 feet. In addition, the geographic location of the Powder River Basin provides us with attractive realized pricing and operating leverage due to its proximity to end markets, installed infrastructure with ample capacity for growth, access to in-basin service providers and what we view as a favorable regulatory climate in the State of Wyoming for hydrocarbon development operations.
As of June 30, 2024, we had approximately 65,000 gross (45,000 net) acres comprised of private, state, and federal lands with a number of large, contiguous leasehold blocks in the over-pressured core of the Powder River Basin, primarily in Campbell and Converse Counties, Wyoming. We have drilled and operate a total of 104 gross (56 net) producing horizontal wells. In addition, we have drilled two gross (one net) horizontal wells awaiting completion. We also own interests in an additional 83 gross (five net) non-operated, producing horizontal wells with an average working interest of approximately 6.0%. All 83 gross (five net) non-operated wells are operated primarily by other leading Powder River Basin operators including EOG Resources, Devon Energy, Anschutz Exploration, and Ballard Petroleum. Our small working interest in these non-operated wells allows us the benefit of ascertaining other operators’ techniques and advances at a relatively small cost. The following map illustrates our acreage positions within the Powder River Basin, consisting primarily of leased acreage in Campbell County, Wyoming, with additional positions in Johnson County and Converse County, Wyoming.
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We have identified 1,770 gross (530 net) horizontal drilling locations across our acreage in the Powder River Basin, the majority of which target the Parkman, Shannon, Turner, Niobrara and Mowry reservoirs. We believe that a significant portion of our inventory in the Turner and Shannon horizons (over-pressured, marine-influenced, tight sandstone formations) and the Parkman horizon (normally pressured, marine-influenced, tight
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sandstone formation) has been substantially delineated by the number of horizontal and vertical wells drilled on or within the vicinity of our acreage and has lowered the geologic and operational risk. Furthermore, we have been actively developing the Mowry and Niobrara horizons, which are both organic-rich, over-pressured, tight shale formations. Combining our results with those of other offset operators, attractive returns in these horizons have been proven at current commodity prices utilizing advanced drilling and completion techniques and technology. We also see additional potential development opportunities in the Teapot, Sussex, Muddy and Dakota formations. Based on our near-term development program, and assuming that we drill an average of eight gross wells per year, we have a multi-decade drilling inventory. We have identified 1,770 gross (530 net) horizontal drilling locations within our approximately 65,000 gross (45,000 net) acre position, of which at a 10% internal rate of return, 658 gross (244 net) locations are currently economic at $55.00 per barrel for oil and $1.85 per MMBtu for natural gas, and 1,198 gross (423 net) locations are economic at $70.00 per barrel for oil and $2.36 per MMBtu for natural gas. Furthermore, if we increase our current development cadence from eight gross wells per year to 24 gross wells per year (i.e., one full-time rig per year), our inventory would still span 27 years using the 658 gross (244 net) locations from the lower pricing assumptions above. As of December 31, 2023, our total estimated proved oil and natural gas reserves were approximately 16,247 Mboe, based on our annual reserve report prepared by Cawley Gillespie. Because our reserves are reported in two streams, the economic value of the NGLs is included in our natural gas price and natural gas reserves. Our proved reserves are comprised of approximately 59% oil and 41% natural gas and are approximately 50% proved developed.
The following table sets forth a summary, as of December 31, 2023, of our gross and net identified horizontal drilling locations by reservoir.
| Identified Horizontal Drilling Locations (1)(2)(3)(4) | ||||||||
| Gross | Net | |||||||
Parkman | 162 | 61 | ||||||
Shannon | 82 | 29 | ||||||
Turner | 259 | 87 | ||||||
Niobrara | 712 | 196 | ||||||
Mowry | 526 | 147 | ||||||
Teapot | 12 | 3 | ||||||
Sussex | 17 | 7 | ||||||
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Total | 1,770 | 530 | ||||||
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| (1) | The above table includes 1,074 gross (354 net) of our identified horizontal drilling locations that have been evaluated by Cawley Gillespie, our independent reserve engineer, along with 696 gross (176 net) identified horizontal drilling locations that have not been evaluated by Cawley Gillespie that were based solely on the internal evaluations of our management. See “Risk Factors — Risks Related to Our Business — A portion of our identified horizontal drilling locations are based on our management’s internal estimates and were not based on evaluations prepared by Cawley Gillespie.” |
| (2) | Identified horizontal drilling locations represent total gross and net locations that have either been evaluated by Cawley Gillespie or specifically identified by management as an estimate of our future multi-year drilling inventory on existing acreage. We have estimated our drilling locations based upon our interpretation of available geologic and engineering data as well as the evaluation of the performance of vertical and horizontal wells drilled on and within the vicinity of our acreage. Our actual drilling activities may change depending on oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add additional reserves to our existing reserves. Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop the related locations. See “Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry—Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.” |
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| (3) | Our identified horizontal drilling location count assumes the following with respect to wells per drilling and spacing unit (“DSU”) and spacing for each of our targeted reservoirs: |
| Gross Wells per DSU | Spacing (in feet) | |||||||
Parkman | 4 | 1,056 | ||||||
Shannon | 2 | 1,760 | ||||||
Turner | 3 | 1,320 | ||||||
Niobrara* | 4 | 1,056 | ||||||
Mowry | 4 | 1,056 | ||||||
Teapot | 3 | 1,320 | ||||||
Sussex | 2 | 1,760 | ||||||
| * | Niobrara locations generally assume four wells per DSU. However, in the eastern portion of Campbell County, the Niobrara develops two distinct reservoirs and as a result, a total of eight gross wells per DSU have been identified (four wells in the Upper Niobrara and four wells in the Lower Niobrara). |
| (4) | One-mile laterals represent horizontal wells expected to be drilled on a 640-acre DSU. Typically, these horizontal wells are drilled with a lateral length of approximately 4,000 feet. Two-mile laterals represent horizontal wells that are drilled across a 1,280-acre DSU. Typically, these horizontal wells are drilled with a lateral length of approximately 9,500 feet. While a portion of our locations represent one-mile laterals, we anticipate there will be increasing opportunities to shift many of these locations towards the drilling and completion of horizontal wells with two-mile laterals. |
The below illustrates the average anticipated production and economic results from the Parkman, Turner, Niobrara and Mowry formations as of December 31, 2023 as well as projected well economics based on management’s estimates for capital expenditures:
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| (1) | Based on Management’s estimates. Projected well economics were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil volumes, the average WTI posted price of $78.22 per barrel as of December 31, 2023, was adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. For natural gas volumes, the average Henry Hub spot price of $2.637 per MMBtu as of December 31, 2023, was similarly adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. All prices are held constant throughout the lives of the properties. |
| (2) | Represents cumulative gross production through the life of the well. |
| (3) | PV-10 is a non-GAAP measure. For more information on how we calculate PV-10 and a reconciliation of PV-10 to its nearest GAAP measure, see “The Offering—Non-GAAP Financial Measures—Reconciliation of PV-10 to Standardized Measure.” |
International Assets
Although our operational focus is on developing our large acreage holdings in the Powder River Basin, in connection with the Reorganization Transactions and immediately prior to the closing of this offering, we will acquire a non-controlling, approximately 16% minority equity position in PSI, a private, Canadian company formed in 1995 and headquartered in Houston, Texas. PSI owns international oil and natural gas assets, primarily in Colombia and Brazil.
PSI operates oil and natural gas fields in Colombia, most of which are located in the Middle Magdalena Valley Basin (Las Monas Block). PSI also operates five oil and gas fields in Romania, with approximately 660 Boe/d, but is planning on a full exit of the country by December 2024. During the year ended December 31, 2023, PSI’s average operated daily net production in Colombia was approximately 2,370 Boe/d with 132 active wells, and PSI’s revenue with respect to its non-RECV operations was approximately $54.4 million.
PSI also owns an indirect interest in Brazilian operations through its approximately 20% ownership of PetroReconcavo S.A. (“RECV”), a publicly-held company that trades on the Sao Paulo Stock Exchange under the ticker symbol RECV3:SAO. As of the close of business on June 30, 2024, RECV’s market capitalization was approximately $979 million. RECV has primarily grown through the acquisition of conventional and mature onshore oil and natural gas properties in Brazil and the subsequent development of those properties. For the year ended December 31, 2023, RECV reported average daily production of approximately 26,000 Boe/d, 835 active wells, revenues of approximately $560 million and $58 million in dividends paid to its shareholders. We account for our non-controlling ownership interest in PSI using the cost method of accounting. The carrying value of the Partnership’s investment in PSI on the balance sheet included in our consolidated financial statements is at cost.
We will acquire our interest in PSI from two investment partnerships managed by Yorktown in the Reorganization Transactions described below. Historically, PSI has paid significant dividends to its shareholders, and we expect PSI to continue to pay dividends in the future, although it has no obligation to do so and we have no influence or control over PSI’s payment of dividends. Since its inception, PSI has paid cumulative dividends on its equity of $14.18 per share, which is equal to approximately 40.5x the original issue price of PSI stock in 1995. We plan to use any future dividends we receive from PSI to fund capital expenditures, to pay cash distributions and for other general uses. For the years ended December 31, 2021, 2022 and 2023, PSI paid aggregate dividends with respect to the approximately 16% minority interest we will acquire in the Reorganization Transaction of $22.1 million, an average of approximately $7.3 million per year.
Development Plan and Capital Budget
Historically, our business plan has focused on acquiring and then developing non-producing acreage. Funding sources for our activities have included cash from our partners, proceeds from borrowings, and cash flow from operating activities.
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We spent approximately $10.6 million on development costs for the year ended December 31, 2023. Our capital budget for the year ending December 31, 2024 is approximately $7.1 million (of which $4.1 million has been paid as of June 30, 2024). Based on current commodity prices and our drilling success rate to date, we expect to fund our 2024 capital development program from cash flow from operating activities and proceeds from this offering. For the twelve months ending December 31, 2025, we intend to use cash flow from operating activities and a portion of our proceeds for this offering to significantly increase capital expenditures to approximately $69.8 million. Our development efforts and capital for the year ending December 31, 2024 are primarily focused on the completion of one gross drilled but uncompleted horizontal well, along with commencing the drilling of two gross (one net) horizontal wells, which are expected to be completed in early 2025. For the years ending December 31, 2025, 2026 and 2027, we anticipate a continued focus on the drilling and completion of additional wells, with 13 gross (11 net) wells expected to be drilled and 10 gross (eight net) wells expected to be completed in 2025, 11 gross (eight net) wells expected to be drilled and 13 gross (11 net) wells expected to be completed in 2026, and six gross (five net) wells expected to be drilled and nine gross (seven net) wells expected to be completed in 2027. The objective of these activities is to consistently grow net production over the next several years.
By operating a high percentage of our acreage, we are better able to control the cadence of our development activities and the corresponding amount and timing of our capital expenditures. We may choose to defer a portion of these planned capital expenditures or modify our rig count depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated commodity prices, the availability of necessary equipment, infrastructure, drilling rigs, labor and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions and drilling and completion costs. Additionally, our projected capital budget includes our expectations regarding the amount of capital that will be required for non-operated development activity. The amount of capital that may ultimately be spent on non-operated development activity may vary based on the development activities of the applicable operators. Any reduction in our capital expenditure budget could delay or limit our development program, which could materially and adversely affect our ability to grow production and our future business, financial condition, results of operations and liquidity. Our development plan and capital budget are based on management’s current expectations and assumptions about future events. While we consider these expectations and assumptions to be reasonable, they are subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. For further discussion of the risks we face, see “Risk Factors—Risks Related to Our Business and the Oil and Natural Gas Industry.”
Our primary business objective is to consistently create significant equity value for our Class A Common Unitholders through a combination of (i) growing our production, cash flow and reserve value and (ii) returning cash to our Class A Common Unitholders through stable and growing cash distributions. To achieve our objective, we intend to execute the following business strategies:
Grow cash flows, reserves and production by developing our extensive oil-focused resource base in the Powder River Basin. We have built an extensive oil-focused inventory of 1,770 gross (530 net) identified horizontal drilling locations predominately targeting our five main producing horizons in the Powder River Basin. We also see additional potential development opportunities in the Teapot, Sussex, Muddy and Dakota formations. We believe our extensive inventory of oil-focused drilling locations, together with our long-lived reserves and operating expertise, will enable us to create equity value by growing cash flow, reserves and production in the current commodity price environment. We intend to utilize these increased cash flows to make quarterly cash distributions to our Class A Common Unitholders, fund future capital programs and grow our acreage position.
Strategically grow our acreage position through opportunistic bolt-on acquisitions and leasing opportunities while increasing our working interest in existing acreage. Our management team has a
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demonstrated track record of identifying and executing on attractive resource development opportunities. Since entering the Powder River Basin in 2012, we have consummated nearly 78 opportunistic bolt-on acquisitions and acreage purchases in the Powder River Basin, acquiring approximately 45,000 net acres as of December 31, 2023. We intend to build upon these successes and pursue similar opportunistic bolt-on and strategic acquisitions in the Powder River Basin. We also expect to continue to use the Wyoming “forced pooling” process to increase our working interest in wells we propose to drill as operator, which could lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well.
Focus on making cash distributions to, and providing long-term value for, our Class A Common Unitholders. Our primary goal is to maximize investor returns through cash distributions and attractive growth of our production and oil and gas reserve value. Our goal is to make a distribution of at least $ per Class A Common Unit per quarter (adjusted for the number of days in the first quarterly period after the closing date of this offering), which we refer to as our initial target quarterly distribution. Although our partnership agreement requires that we distribute all of our Available Cash, if any, quarterly, we have no legal obligation to do so, and there is no guarantee that we will make quarterly cash distributions to our Class A Common Unitholders at the initial target quarterly distribution amount, or at all, or that distributions will grow over time. However, we intend to grow production annually and acquire acreage over time, while continuing to provide consistent quarterly distributions to our Class A Common Unitholders at or above our initial target quarterly distribution, with a goal of increasing the long-term value of our Class A Common Units.
Maintain financial flexibility with a conservative capital structure and a strong liquidity profile. We intend to conduct our operations primarily through cash flow generated from operations with a focus on maintaining a strong balance sheet with significant cash reserves and little to no net debt. We intend to initially keep our existing debt facility in place, but we are currently negotiating a New Credit Facility (as defined below) with prospective lenders. If we enter into a New Credit Facility after the closing of this offering, we will use borrowings under the New Credit Facility and a portion of the proceeds from this offering to repay in full and terminate our Existing Credit Agreement (as defined below). See “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction—Expected Refinancing Transactions” for additional information. Due to our strong operating cash flows and post-offering liquidity, we expect to have substantial flexibility to fund our capital budget and to potentially accelerate our drilling program as conditions warrant. Our focus is on the economic extraction of hydrocarbons while maintaining a prudent leverage ratio and strong liquidity profile. Although we may use leverage to make accretive acquisitions, we expect to do so with the long-term goal of maintaining a strong balance sheet. To mitigate the risk associated with volatile commodity prices and to satisfy the requirement under our Existing Credit Agreement (as hereinafter defined), we will hedge a portion of our production volumes, on a rolling quarterly basis, based on reasonably anticipated projected production of proved developed producing reserves that we are required to hedge.
Leverage our geologic and operational expertise to enhance operating efficiencies and maximize returns. We believe our management and technical teams are among the best operators in the Powder River Basin. We regularly benchmark our operating data against our own historical results as well as those of other Powder River Basin operators in order to evaluate our performance, identify opportunities to improve our drilling and completion techniques and make informed decisions about our capital program and drilling activity levels. Our team is focused on utilizing our geologic expertise to analyze the geological characteristics of the horizons we intend to develop, which allows us to develop techniques specifically tailored to each horizon.
Improve returns through the use of advanced drilling and completion techniques, technology and increasing lateral lengths. We continuously seek efficiencies in our drilling, completion and production techniques to optimize ultimate resource recoveries, rates of return and cash flows. Since inception, we have strived to be on the leading-edge of deploying advanced completion technology in the Powder River Basin. We intend to continue to leverage our management and technical teams’ geologic and operational experience in applying unconventional drilling and completion techniques in the Powder River Basin to maximize our returns and will allocate capital towards next generation technologies where applicable.
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We believe that the following strengths will allow us to successfully execute our business strategies:
Our sole basin focus promotes optimized development of our concentrated position in the oil and liquids-rich Powder River Basin. While we have exposure to international production through our non-controlling position in PSI, our primary and sole operating focus is on the development of our Powder River Basin assets. Additionally, while the majority of the top operators in the Powder River Basin are large, diversified companies with operations in multiple basins, our operations are focused exclusively in the Powder River Basin. As of December 31, 2023, we were the fifth largest private pure Powder River Basin operator based on gross equivalent production, and the tenth largest producer overall in the Powder River Basin. Our single basin focus has allowed us to develop expertise in the Powder River Basin and to work on refining area-specific drilling and completion designs. Upon completion of this offering, we will be the only public company solely operating in the Powder River Basin, and we intend to leverage our deep knowledge of the basin, along with our understanding of the geology and reservoir properties of potential acquisition targets, to identify and opportunistically acquire prospective bolt-on acreage that improves our potential drilling outcomes and meets our strategic and financial objectives.
Highly experienced management team with a track record of creating value. Our management team has an established track record operating in the Powder River Basin and other premier onshore U.S. basins and is experienced in the identification, evaluation, execution and integration of acquisitions. Members of our management team have a long history of working together on the cost-efficient management of leading-edge development programs, including three in the Granite Wash (Anadarko Basin), the Barnett Shale (Fort Worth Basin) and the Bakken Shale (Williston Basin). Our Chief Executive Officer and Yorktown have led activities in other active plays and basins, growing a cumulative investment of approximately $340 million to approximately $1 billion over the course of three successful upstream exit transactions, with an average return on investment of 296%, excluding general and administrative and other expenses. We believe our management team is able to leverage their experience to create equity value through organic development of our existing assets and opportunistic acquisitions; however, the prior performance of companies or business initiatives in which our management team or Yorktown were involved may not be indicative of our future performance.
Low-risk acreage position with multi-year inventory of oil-weighted drilling locations. We have a large inventory of drilling opportunities in the core of the Powder River Basin. As of December 31, 2023, our horizontal drilling inventory evaluated by Cawley Gillespie consisted of 1,074 gross (354 net) locations, primarily targeting the Parkman, Shannon, Turner, Niobrara and Mowry horizons. Between September 1, 2024 and December 31, 2026, we expect to drill 26 gross (20 net) operated wells and complete 23 gross (19 net) operated wells. Based on our near-term development program, assuming we drill an average of eight gross wells per year, we have a multi-decade opportunity set. We have identified 1,770 gross (530 net) horizontal drilling locations within our approximately 65,000 gross (45,000 net) acre position, of which at a 10% internal rate of return, 658 gross (244 net) locations are currently economic at $55.00 per barrel for oil and $1.85 per MMBtu for natural gas, and 1,198 gross (423 net) locations are economic at $70.00 per barrel for oil and $2.36 per MMBtu for natural gas. Furthermore, if we increase our current development cadence from eight gross wells per year to 24 gross wells per year (i.e., one full-time rig per year), our inventory would still span 27 years using the 658 gross (244 net) locations from the lower pricing assumptions above. Our production stream is oil weighted, and we envision increasing our average oil production from 55-60% to approximately 60-70% of our total equivalent production over the next three years.
Balanced asset portfolio with significant capital allocation flexibility. Our acreage spans all hydrocarbon mix windows of the Powder River Basin, giving us the flexibility to adjust our capital plan and drilling program to rebalance our production as the commodity price environment evolves. Because approximately 70% of our net acreage position was held by production as of December 31, 2023, and we have the ability to extend many of our material, non-producing leases beyond 2026 for approximately $2.5 million and potentially renew the remaining non-producing leases beyond 2026 for an additional $1.4 million, we are able to opportunistically allocate our
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human and capital resources to focus on certain windows to produce the commodity mix that is expected to provide the highest potential rate of return at that given time.
Positioned in the Powder River Basin with existing infrastructure built to gather and transport higher volumes than are currently being produced in the basin results in a present-day underutilization. The first oil well in the Powder River Basin was drilled in 1889. Since that time, the Powder River Basin has experienced multiple waves of conventional development. Starting in 2012, horizontal development began and production growth followed. As of December 2023, the Powder River Basin was producing nearly 181 MBbls/d – roughly four times the production from the low in 2009. The Powder River Basin has available refining and takeaway capacity of 1,097 MBbls/d, significantly above current production. Our average net daily production for the year ended December 31, 2023 was approximately 2,947 Boe/d, from approximately 60 net wells. As a result of the legacy production along with the recent upswing in activity, we believe the oil infrastructure in place across our acreage has sufficient capacity to support our anticipated production growth.
Geographically advantaged assets with regional price advantages. Our acreage position is in close proximity to end markets for our oil and natural gas, which provides us with a regional price advantage. For example, in 2023, we sold all of our operated oil production to purchasers in the Powder River Basin, which was then refined in Casper, Rawlins or Newcastle, Wyoming, which are all approximately 75 miles from our acreage position. We expect to continue to sell a majority of our operated oil production on a go-forward basis at attractive prices with all-in differentials of approximately ($3.00) per barrel against the NYMEX WTI. Our operated natural gas also realizes competitive pricing. For example, in 2023, we sold all of our operated natural gas production for $0.02/Mcf over NYMEX Henry Hub, including all transportation, compression and enhancement fees and percentage of proceeds paid to the gas gatherers and marketers. We expect to continue to sell a majority of our operated natural gas production on a go-forward basis at attractive prices that are at or near NYMEX Henry Hub pricing.
Strong relationships with local landowners and government authorities. We have purposefully developed strong relationships with surface and mineral interest owners in the Powder River Basin, which we believe provides us with a competitive advantage in acquiring additional leasehold and operatorship positions. Furthermore, our management’s substantial experience in the Powder River Basin and extensive interactions with the relevant state and federal regulatory bodies allow us to efficiently and effectively navigate the regulatory process, which affords us opportunities to assume operatorship and expand our ownership.
Significant operational control allowing us to improve drilling results and economic returns. As operator, we are able to control the timing and design of our development program. We believe this affords us the flexibility to efficiently develop our acreage by adjusting drilling, completion and production activities opportunistically to react to changes in the operational and economic environment, such as changes in commodity prices, service costs and access to services.
Exposure to international operations and supplemental cash dividends. Through our approximately 16% non-controlling investment in PSI, we anticipate receiving future cash dividends. For the years ended December 31, 2021, 2022 and 2023, PSI paid aggregate dividends with respect to the approximately 16% minority interest we will acquire in the Reorganization Transaction of $22.1 million, an average of $7.3 million per year. We believe that our ownership position in PSI will continue to provide us with cash dividends to supplement our operational cash flow; however, we are not solely relying on these dividends in our financial planning and budgeting.
Powder River Basin, Wyoming USA
Since our entry into the Powder River Basin in 2012, we have diligently pursued strategic growth opportunities and executed a comprehensive acquisition and leasing strategy. Our proactive approach has enabled us to secure
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valuable acreage in Campbell, Converse and Johnson Counties, positioning us as a significant operator in the basin. Through ongoing leasing efforts and collaborative acreage trades with prominent operators such as EOG Resources, Anschutz Exploration, and Devon Energy, we have strengthened our acreage position. We have completed over 70 acquisitions, the most sizeable of which being 7,478 net acres in May 2012, 3,444 net acres in March 2013, 9,208 net acres in April 2013, 1,578 net acres in June 2014, 7,875 net acres in July 2014, and 4,841 net acres in September 2015. Additionally, we acquired 6,409 net acres in Federal Bureau of Land Management (“BLM”) and State of Wyoming lease sales beginning in 2013, further bolstering our acreage position. In May 2020, we established a Federal Exploratory Unit in Converse County, demonstrating our proactive approach to resource development and operational efficiency. This unit, anchored by an initial test well with minimal drilling requirements, underscores our commitment to responsible resource management and value creation for our stakeholders.
Our management team believes the development and exploitation of unconventional assets in the Powder River Basin is among the most economic oil and natural gas plays in the United States. Based on current commodity prices, we anticipate drilling two gross (one net) horizontal wells, with completions set in early 2025, in addition to participating in non-operated well proposals that meet our return thresholds.
We currently produce oil and natural gas from five different zones in the Powder River Basin, which includes the Parkman, Shannon, Turner, Niobrara and Mowry formations. With the exception of the Parkman, which is normally pressured, all of the remaining reservoirs are over-pressured by conventional standards. In addition to these formations, there is established vertical production nearby in the Teapot, Sussex, Muddy and Dakota formations, which could create future opportunities for horizontal development for the Company.
The Parkman, Shannon and Turner formations are marine-influenced sandstones. These formations have been fairly well delineated through historical vertical and more recent horizontal development. Porosity in these formations ranges from 6.0%-18.0%, with typical GOR ranging from 500-1,000 scf/STB, but as high as >20,000 scf/STB in the Turner on the east side of our acreage. Pressure gradients in the Parkman range from approximately 0.4 – 0.5 pounds per square inch/ft, while the Shannon and Turner formations range from 0.5 – 0.7 pounds per square inch/ft.
The Niobrara and Mowry formations are marine, organic-rich shales. Both of these formations are more ubiquitous on our acreage than the sandstone reservoirs, yielding significantly more locations in our inventory. The Niobrara shale is a calcareous siltstone and shale unit with 2.0%-5.0% TOC and GORs ranging from 1,000-7,000 scf/STB. Overall, the Niobrara averages 300-350 feet in thickness and typically has pressure gradients in the 0.5-0.7 pounds per square inch/ft. Geologic mapping and recent production results have identified two productive intervals within the Niobrara over a portion of our acreage in eastern Campbell County. While the lower Niobrara is only present in the eastern portion of our Campbell County acreage, the upper Niobrara is present and has been proven productive over the vast majority of our acreage in Campbell and Converse counties.
The Mowry shale is currently our deepest producing reservoir, averaging 160 feet thick. It is comprised of silicious siltstone and shale, with varying amounts of bentonite beds, and like the Niobrara has TOCs in the range of 2.0%-5.0%. The Mowry is significantly over-pressured, in some cases exceeding 0.7 pounds per square inch/ft. Depending on the area of interest, the Mowry has varying GORs, ranging from 1,000-3,000 scf/STB in our western Campbell County acreage to 3,500 – 20,000 scf/STB in our eastern Campbell County acreage. The Mowry potential in Converse County is fairly untested, but recent tests by other operators should shed light on potential in this area in the near future.
Drilling and Completion Activities
The evolution of our operated horizontal drilling and completion activity can be defined by (1) target formation and (2) lateral length. Beginning with our first wells in 2012 through 2013, our initial reservoir targets focused on the development of the Shannon and Turner sandstone reservoirs, drilling seven Shannon wells and six Turner wells. From 2014 through 2017, we drilled an additional 19 Shannon and 22 Turner wells as well as
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five Parkman, our initial Niobrara well and four Mowry wells. Since 2018 until present time, we drilled an additional 13 Parkman wells, one Shannon well, 19 Turner wells, three Niobrara wells, and six Mowry wells.
Prior to 2017, the vast majority of our drilling and completion activity involved one-mile laterals (<5,280 feet) where we drilled a total of 55 one-mile laterals and two two-mile laterals (<10,560 feet). From 2017 to present, we have focused primarily on drilling two-mile laterals, with 22 one-mile laterals and 27 two-mile laterals being drilled. Furthermore, we have not drilled any one-mile laterals since 2020, focusing exclusively on two-mile laterals. Going forward, we expect to continue prioritizing the development of two-mile laterals, except where not possible due to prior development.
| Operated Drilled Well Count | ||||||||
| One-mile Laterals (<5,280’) | Two-mile Laterals (>5,280’) | |||||||
Parkman | 13 | 5 | ||||||
Shannon | 22 | 5 | ||||||
Turner | 38 | 9 | ||||||
Niobrara | 0 | 4 | ||||||
Mowry | 4 | 6 | ||||||
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Total Wells Drilled | 77 | 29 | ||||||
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Reserves
Evaluation and Review of Reserves. Our estimated net oil and natural gas reserves as of December 31, 2023 and December 31, 2022 included in this prospectus are based on evaluations prepared by the independent petroleum engineering firm, Cawley Gillespie, in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering similar resources.
Cawley Gillespie is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. The lead evaluator that prepared the reserve report was Zane Meekins, P.E., Executive Vice President at Cawley Gillespie.
Mr. Meekins has been with Cawley Gillespie since 1989 and graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins is a State of Texas registered professional engineer (License #71055) and a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Mr. Meekins is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
We maintain an internal staff of engineers and geoscience professionals who are responsible for the internal review of our reserve estimates and work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our reserves relating to our assets in the Powder River Basin. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the reserve estimation 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.
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For all of our properties, our internally prepared reserve estimates as well as the reserve reports prepared by Cawley Gillespie are reviewed and approved by our Vice President, Reservoir Engineering, Tom Loveland. Mr. Loveland has been with us since November 2015 and has more than 23 years of experience in reservoir engineering and reserve management.
The preparation of our reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
| • | review and update potential well locations and lateral lengths by formation, based on existing leasehold; |
| • | verification of property ownership by our land department; |
| • | review and verification of historical production data, as reported by us for producing wells we operate, and by our partners for wells in which we are not the designated operator; |
| • | analysis of lease operating expenses and future well costs by operation personnel; |
| • | preparation of existing well oil, gas, and water forecasts, as well as type well forecasts for future wells; and |
| • | calculation of reserve estimates using all previously described data. |
Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. 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 reserves as of December 31, 2023 and December 31, 2022 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 four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for our PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods and existing analog wells that are believed to share geologic characteristics, fluid characteristics, and operational characteristics with those properties. These are industry-proven methods that provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties. The reasonable time that hydrocarbon extraction commences is most commonly deemed to be within five years of the effective date of a reserve report.
To estimate economically recoverable proved reserves and related future net cash flows, Cawley Gillespie considers many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data that cannot be measured directly, but that result in forecasts of future production rates, economic criteria based on current cost estimates and actual operating expenses, and the SEC pricing requirements.
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Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, historical well cost and operating expense data.
Summary of Oil and Natural Gas Reserves. The following table summarizes our estimated net oil and natural gas reserves as of December 31, 2023 and December 31, 2022, based on reports prepared by Cawley Gillespie. Our reserves are reported in two streams: oil and natural gas. The economic value of the NGLs is included in our natural gas price and reserves. All of these reserve estimates were prepared in accordance with the SEC’s rule regarding reserve reporting currently in effect. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business and Properties—Oil and Natural Gas Data—Reserves” in evaluating the material presented below.
| As of December 31, 2023(1)(2) | As of December 31, 2022(3) | |||||||
Proved Reserves: | ||||||||
Oil (MBbls) | 9,515 | 7,411 | ||||||
Natural Gas (MMcf) | 40,392 | 36,548 | ||||||
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Total Proved Reserves (Mboe) | 16,247 | 13,502 | ||||||
Proved Developed Reserves: | ||||||||
Oil (MBbls) | 4,579 | 5,700 | ||||||
Natural Gas (MMcf) | 21,327 | 23,875 | ||||||
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Total Proved Developed Reserves (Mboe) | 8,134 | 9,679 | ||||||
Proved Undeveloped Reserves: | ||||||||
Oil (MBbls) | 4,936 | 1,711 | ||||||
Natural Gas (MMcf) | 19,065 | 12,673 | ||||||
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Total Proved Undeveloped Reserves (Mboe) | 8,114 | 3,823 | ||||||
| (1) | Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil volumes, the average WTI posted price of $78.22 per barrel as of December 31, 2023, was adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. For natural gas volumes, the average Henry Hub spot price of $2.637 per MMBtu as of December 31, 2023, was similarly adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. All prices are held constant throughout the lives of the properties. |
| (2) | The development plan associated with the 2023 proved reserves includes the use of cash flow from operations as well as a portion of the estimated net proceeds from the offering. |
| (3) | Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil volumes, the average WTI posted price of $93.67 per barrel as of December 31, 2022, was adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. For natural gas volumes, the average Henry Hub spot price of $6.358 per MMBtu as of December 31, 2022, was similarly adjusted for oil and gas differentials, which may include local basis differentials, transportation, gas shrinkage, and gas heating value (BTU content) and/or crude quality and gravity corrections. All prices are held constant throughout the lives of the properties. |
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Reserve engineering is and must be recognized as 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 variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Risk Factors” appearing elsewhere in this prospectus.
Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this prospectus.
Proved Undeveloped Reserves
As of December 31, 2023, our PUDs were composed of 4,936 MBbls of oil and 19,065 MMcf of natural gas, for a total of 8,114 Mboe. As of December 31, 2022, our PUDs were composed of 1,711 MBbls of oil and 12,673 MMcf of natural gas, for a total of 3,823 Mboe. PUDs are converted from undeveloped to developed as the applicable wells begin production.
The following table summarizes our changes in PUDs during the years ended December 31, 2023 and 2022 (in Mboe):
Balance, December 31, 2021 | 3,489 | |||
Purchases of reserves | — | |||
Extensions and discoveries | 292 | |||
Performance revisions of previous estimates | — | |||
Price impact | 42 | |||
Transfers to proved developed reserves | — | |||
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Balance, December 31, 2022 | 3,823 | |||
Purchases of reserves | — | |||
Extensions and discoveries | 6,100 | |||
Performance revisions of previous estimates | 209 | |||
Price impact | (1,822 | ) | ||
Transfers to proved developed reserves | (196 | ) | ||
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Balance, December 31, 2023 | 8,114 |
During the year ended December 31, 2022, we did not convert any PUDs to proved developed reserves. Accordingly, we did not incur any costs relating to the development of PUDs during the year ended December 31, 2022. Since our development program consisted only of completing wells that were classified as probable there were not any proved undeveloped reserves converted to proved developed reserves during this period.
During the year ended December 31, 2023, we converted one PUD to proved developed reserves for 196 Mboe at an associated capital cost of $3.6 million. The development schedule for our undeveloped property takes into account the proceeds from this offering, increasing our available capital and resulting in an increase in the development schedule of unproved property, which added 18 PUD locations totaling 6,100 Mboe. In addition, our PUDs include positive performance revisions of 209 Mboe due to increased performance from our wells and other analogs in our Mowry and Niobrara areas. For the year ended December 31, 2023, oil and natural gas prices calculated in accordance with SEC guidelines decreased by 16.5% and 58.5%, respectively, as compared to the year ended December 31, 2022, resulting in five PUDs being removed from our drill schedule representing 1,822 Mboe.
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All of our PUD drilling locations are scheduled to be drilled within five years of December 31, 2023. We expect to drill approximately three gross PUD locations during 2024. We anticipate drilling and/or completing or participating in the drilling and/or completion of approximately seven gross PUD locations during 2025, six during 2026, one during 2027 and seven during 2028. These PUD locations relate to 8,114 MBoe of PUD reserves. Our total future development costs relating to the development of our PUDs at December 31, 2023 were expected to be approximately $122.5 million between 2024 and 2028. All of these PUD drilling locations are part of a development plan and a budget that is reviewed annually and adopted by management. We expect that the cash flow generated by our then-producing wells, in addition to availability under our New Credit Facility (which we are currently negotiating), the proceeds of this offering and the issuance of additional debt or equity securities will be sufficient to fund our drilling program, maintenance capital expenditures and PUD conversion into proved developed reserves in accordance with our development schedule. Please see “Risk Factors — Risks Related to Our Business — The development of our estimated undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated undeveloped reserves may not be ultimately developed or produced.”
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Oil and Natural Gas Production Prices and Production Costs
Production and Price History
The following table sets forth information regarding net production of oil and natural gas, and certain price and cost information for the periods indicated. Our reserves and production are reported in two streams: crude oil and natural gas. The economic value of the NGLs is included in the natural gas price and reserves. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
| Predecessor Combined Historical | ||||||||||||||||
| Six Months Ended June, 30, | Year Ended December 31, | |||||||||||||||
| 2024 | 2023 | 2023 | 2022 | |||||||||||||
Summary Historical Operating Data: | ||||||||||||||||
Production and Operating Data: | ||||||||||||||||
Net production volumes: | ||||||||||||||||
Oil (MBbls) | 288 | 326 | 625 | 809 | ||||||||||||
Natural gas (MMcf) | 1,269 | 1,471 | 2,705 | 2,982 | ||||||||||||
Total (Mboe) | 500 | 571 | 1,076 | 1,306 | ||||||||||||
Average net production (Boe/d) | 2,745 | 3,154 | 2,947 | 3,578 | ||||||||||||
Average sales prices(1): | ||||||||||||||||
Oil sales (per Bbl) | $ | 76.50 | $ | 73.70 | $ | 76.04 | $ | 93.27 | ||||||||
Oil sales with derivative settlements (per Bbl) | $ | 72.18 | $ | 67.57 | $ | 70.12 | $ | 66.06 | ||||||||
Natural gas sales (per Mcf) | $ | 1.98 | $ | 2.69 | $ | 2.45 | $ | 6.44 | ||||||||
Natural gas sales with derivative settlements (per Mcf) | $ | 2.76 | $ | 2.44 | $ | 2.46 | $ | 3.37 | ||||||||
Average price per Boe | $ | 49.10 | $ | 48.98 | $ | 50.33 | $ | 72.48 | ||||||||
Average price per Boe with derivative settlements | $ | 48.63 | $ | 44.85 | $ | 46.92 | $ | 48.61 | ||||||||
Average unit costs per Boe: | ||||||||||||||||
Lease operating expenses | $ | 12.80 | $ | 11.98 | $ | 12.97 | $ | 10.85 | ||||||||
Production and ad valorem taxes | $ | 6.54 | $ | 7.08 | $ | 6.98 | $ | 8.72 | ||||||||
Depletion, depreciation and amortization | $ | 14.34 | $ | 23.26 | $ | 26.78 | $ | 23.68 | ||||||||
Accretion | $ | 0.23 | $ | 0.20 | $ | 0.21 | $ | 0.17 | ||||||||
Abandonment | $ | 3.95 | $ | 5.07 | $ | 2.73 | $ | 0.88 | ||||||||
Impairment of oil and natural gas properties | $ | — | $ | — | $ | 104.00 | — | |||||||||
General and administrative expenses | $ | 8.98 | $ | 7.13 | $ | 7.28 | $ | 5.63 | ||||||||
| (1) | Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains or losses on cash settlements for commodity derivative transactions and premiums paid or received on options, if any, that settled during the period. |
Productive Wells
The following table sets forth information regarding our productive horizontal wells in which we have working interest as of June 30, 2024:
| Gross | Net | Average Working Interest | ||||||||||
Oil Wells | 130 | 50 | 38.5 | % | ||||||||
Natural Gas Wells | 57 | 11 | 19.3 | % | ||||||||
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Total | 187 | 61 | 32.6 | % | ||||||||
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As of June 30, 2024, of our 187 gross (61 net) productive horizontal wells, we operated 104 gross (56 net) producing horizontal wells with an average working interest of 53.9%, of which 85 gross (46 net) wells were oil wells and 19 gross (10 net) wells were natural gas wells. Of our 104 gross operated horizontal wells producing as of June 30, 2024, we have increased our average working interest by 11.8% over the life of the project as a result of force pooling interests in 69 gross horizontal wells. We have also increased our working interest by an average 16% by acquiring additional interests in seven gross horizontal wells. Productive wells consist of producing wells and wells capable of production, including 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.
Developed and Undeveloped Acreage
The following table delineates our developed and undeveloped leasehold acreage within the Powder River Basin as of June 30, 2024. “Developed Acres” denotes acres assigned to the drilling and spacing unit of productive wells. “Undeveloped Acres” are acres in which wells have not yet been drilled and completed to facilitate the production of commercial quantities of oil and/or natural gas, irrespective of the reserve classification. A Developed Acre does not signify full development, which would preclude the possibility of future infill wells; it simply indicates that the acreage falls within a drilling and spacing unit of a currently producing well. “Gross Acres” denotes acres with an owned working interest, while “Net Acres” represents the cumulative fractional ownership working interests in Gross Acres. The total of Net Acres represents the sum of fractional working interests owned within Gross Acres, expressed as whole numbers and fractions.
Formation | Developed Gross | Developed Net | Undeveloped Gross | Undeveloped Net | Developed % | Total Gross | Total Net | |||||||||||||||||||||
Parkman | 5,734 | 3,583 | 58,279 | 41,396 | 9 | % | 64,013 | 44,979 | ||||||||||||||||||||
Shannon | 14,548 | 9,127 | 50,544 | 35,512 | 26 | % | 65,092 | 44,638 | ||||||||||||||||||||
Niobrara | 5,225 | 2,951 | 59,276 | 41,754 | 7 | % | 64,501 | 44,705 | ||||||||||||||||||||
Turner | 20,195 | 12,248 | 44,150 | 33,187 | 37 | % | 64,345 | 45,435 | ||||||||||||||||||||
Mowry | 4,632 | 2,280 | 60,000 | 42,068 | 5 | % | 64,633 | 44,348 | ||||||||||||||||||||
Average | 10,067 | 6,038 | 54,450 | 38,783 | 16 | % | 64,517 | 44,821 | ||||||||||||||||||||
Some of the leases comprising the Undeveloped Acres outlined in the table above are slated for expiration upon the conclusion of their respective primary terms unless production is established from the lease prior to such expiration, in which case the lease will remain in effect until production ceases. We are committed to actively pursuing extensions and renewals for all significant leases in this situation. As of June 30, 2024, we estimate an expenditure of approximately $3.9 million to extend or renew every significant lease set to expire through the end of 2026. This estimation does not take into account the drilling of undeveloped locations and maintaining the expiring leases through production; thus, we do not anticipate a significant reduction in our reserves due to lease expirations. The following table presents the Undeveloped Net Acres that are set to expire within the specified years if no production is established thereon, and the estimated cost to extend or renew said acreage.
Year | Net Acres Expiring | Estimated Cost to Extend or Renew | ||||||
2024 | 2,830 | $ | 496,934 | |||||
2025 | 3,921 | $ | 656,895 | |||||
2026 | 3,471 | $ | 1,535,282 | |||||
Should we either be unable or decide not to renew or extend the above leases, approximately 753 MBbl and 3,551 MMcf (1,335 Mboe) of PUD reserves would be impacted.
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The following table sets forth information with respect to the number of wells drilled during the periods indicated in which we had an interest. 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.
| Six Month Ended June 30, 2024 | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Developed Wells | ||||||||||||||||||||||||
Productive(1) | ||||||||||||||||||||||||
Oil Wells | — | — | 22 | 1 | 2 | — | ||||||||||||||||||
Natural Gas Wells(2) | — | — | 21 | 1 | 13 | 0.5 | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
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Total | 43 | 2 | 15 | 0.5 | ||||||||||||||||||||
Exploratory Wells | ||||||||||||||||||||||||
Productive(1) | ||||||||||||||||||||||||
Oil Wells | — | — | — | — | — | — | ||||||||||||||||||
Natural Gas Wells(2) | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
Total | — | — | — | — | — | — | ||||||||||||||||||
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Total Wells | — | — | 43 | 2 | 15 | 0.5 | ||||||||||||||||||
| (1) | Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history. |
| (2) | Wells are designated gas if they have estimated ultimate gas / oil ratio of 6,000 scf/Bbl or higher. Because our reserves and production are reported in two streams, the economic value of NGLs is included in our natural gas wells. |
General
We operated approximately 90% of our net production for the year ended December 31, 2023. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Marketing and Customers
We market the majority of the production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to purchasers at market prices.
During the year ended December 31, 2023, 100% of our combined oil and natural gas production was sold to five customers. For the six months ended June 30, 2024, 100% of our combined oil and natural gas operated production was sold to three customers. We do not believe that the loss of a single purchaser would materially affect our business because there are numerous other potential purchasers in the area in which we sell our production. However, the loss of one of our top two purchasers, HF Sinclair Refining & Marketing LLC and
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Thunder Creek Gas Services, LLC (purchased by WGR Operating, LP at the end of 2023), our ability to sell our production to other purchasers on terms we consider acceptable, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could have a short-term impact on our financial condition, results of operations and ability to make distributions to our unitholders.
| For the Six Months Ended June 30, 2024 | For the Year Ended December 31, 2023 | |||||||
HF Sinclair Refining & Marketing LLC | 91 | % | 87 | % | ||||
Thunder Creek Gas Services, LLC | — | 11 | % | |||||
WGR Operating, LP(1) | 9 | % | 1 | % | ||||
Wyoming Refining, Co. | — | 1 | % | |||||
Evolution Midstream, LLC | — | <1 | % | |||||
EOG Resources, Inc. | <1 | % | — | |||||
| (1) | WGR Operating, LP acquired Thunder Creek Gas Services, LLC in 2023. |
Transportation
We consider our gathering and delivery infrastructure sufficient for our production. Our oil is collected from the wellhead to our tank batteries and then transported by the purchaser by truck or pipeline to a tank farm, another pipeline or a refinery. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point. Aside from our gathering agreements for both oil and natural gas, which are necessary for our business, we are not subject to any long-term delivery commitments or minimum volume commitments for the transportation of our production.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that 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 identify suitable properties where we have a competitive advantage due to our knowledge of the basin or landowner relations, allowing us to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many of our competitors, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger 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.
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Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with the acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform title curative work with respect to significant title defects affecting our leasehold prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on our leasehold, we are responsible for curing such defects at our expense. Title defects affecting interest owned by non-operators in our wells are the responsibility of such non-operators to cure. We have obtained title opinions on all of our operated 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 a review of title materials in the seller’s records to confirm the ownership of the most significant leases and, depending on the materiality of properties, we may perform additional title due diligence by reviewing the courthouse records in the county where the properties are located. 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.
Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.
Wyoming Statutory Pooling Process
The State of Wyoming’s oil and gas regulatory body, the Wyoming Oil & Gas Conservation Commission (“WOGCC”), has rules and regulations that are designed to promote the exploration and development of oil and natural gas wells. One such regulation that allows companies to drill wells without the consent of all interest owners in a DSU is known as statutory pooling (aka “forced pooling”). As of December 31, 2023, we have filed 162 APDs with the WOGCC, most of which will have interest owners within the DSU who are either unwilling or unable to voluntarily pool their interest with ours in order to participate in the drilling of a well, thus requiring the interest to be force pooled. Wyoming’s pooling statute, W.S. 30-5-109, is a time-consuming regulatory burden that requires significant work before and after a well is drilled. Prior to drilling a well with separately owned interests in the DSU, a good faith effort must be made to secure voluntary participation of all interest owners in the lands within the DSU. For those interest owners who are unwilling or unable to participate in a well (“Non-Participating Owners”), a force pooling application is filed with the WOGCC to set a date for a pooling hearing. At such pooling hearing, evidence of our efforts to secure voluntary participation is presented, and a pooling order is issued by the Commission.
Alternatively, there may be instances where operators of adjacent leases propose a well to us and initiate forced pooling actions to include our leasehold interests without our consent. When this occurs, if we are unwilling or unable to participate in the proposed well, we make every effort to prevent our interest from being force pooled by allowing others to participate in our stead for a fee.
Pooling orders provide for the drilling and operation of a well in a DSU and for payment of the costs thereof. The parties paying for the drilling of the well are entitled to all production from the well after payment of royalty and other obligations payable out of production. Parties with working interest located within the DSU
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who opt not to participate, and allow their interest to be force pooled, will be subject to a risk penalty that is substantially greater than the initial cost to participate. The penalties associated with a force pooled working interest in a well are as follows:
Up to:
Three hundred percent (300%) of that portion of the costs and expenses of drilling, reworking, deepening or plugging back, testing and completing, after deducting any cash contributions received and up to two hundred percent (200%) of that portion of the cost of newly acquired equipment in the well, to and including the wellhead connections, which would have been chargeable to the nonconsenting owner if they had participated therein, if the nonconsenting owner’s tract or interest is subject to a lease or other contract for oil and gas development;
The WOGCC has consistently authorized the maximum penalty for our horizontal development.
The availability of forced pooling means that normally it is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Our strategy is to use the forced pooling process to proceed with the desired development of our wells. In this manner, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas. In addition to leased acreage, pooled units within the Powder River Basin may expand to include both state and federal lands. The pooling of federal lands requires additional steps beyond those required for state and fee lands. DSUs containing any amount of federal lands are required to have a Federal Communitization Agreement that allows for the unitization or pooling of federal and non-federal oil and gas leases within the DSU.
We have employed another method of developing federal lands with the formation of the INOT (Deep) Federal Exploratory Unit. Federal exploratory onshore units are formed by virtue of the execution of two separate agreements: (i) the unit agreement (“UA”), which is a contract between the BLM and the working interest owner designated as operator (the “Proponent”), and (ii) the unit operating agreement (“UOA”), which is executed by the unit working interest owners and sets forth the cost allocation formula for the implementation of the UA, operational provisions and voting procedures.
Pooling approval is based on whether the proposed unitization serves the public interest of conservation of natural resources. As a general rule, the Proponent of the unit must have 85% of all tracts committed to the unit to demonstrate to the BLM effective control of the unit area. Once approved, commencement of the first test well (“Initial Obligation Well”) must begin within six months following the effective date of the UOA and must be drilled to the objective depth or until unitized substances are discovered. We successfully drilled and completed the Initial Obligation Well in the INOT (Deep) Unit, and it was deemed a well capable of producing unitized substances in paying quantities in accordance with the UA and the BLM. A Participating Area (“PA”) was formed around the Initial Obligation Well to reflect the drainage area and to define the lands regarded as reasonably proved to be productive of unitized substances in paying quantities. As additional wells are drilled in the INOT (Deep) Unit, the PA will expand and all costs incurred in the development and operation of wells within the PA, and the production therefrom, will be proportionally shared amongst all working interests in the PA. If a well is completed and not included in a PA, the well, production, materials and equipment costs and all lease burdens shall be borne and paid by the parties to the drilling block.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Seasonal anomalies such as mild winters or mild summers also may impact demand and prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
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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 are generally between 15-20% (8/8ths). Our working interest for all operated producing horizontal wells averages approximately 53% and our net revenue interest is approximately 43%.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs have not had a material adverse effect on our results of operations; however, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
Regulation Affecting Production
The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which we own or operate producing oil and natural gas properties, including Wyoming, have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and natural gas we can drill. Moreover, each state, including Wyoming, generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance 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 limit the number of locations we can drill.
The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation Affecting Sales and Transportation of Commodities
Sales prices of oil, natural gas, condensate and NGLs are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil, natural gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to certain state and federal reporting requirements.
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The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of oil and natural gas we produce, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil and natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for oil and natural gas production, if any, of the drilling program and the cost of such capacity. Further state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.
FERC regulates interstate natural gas pipeline transportation rates and terms and conditions of service. FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. The stated purpose of many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.
In addition to the regulation of natural gas pipeline transportation, FERC has jurisdiction over the purchase or sale of natural gas or the purchase or sale of transportation services subject to FERC’s jurisdiction. Under the NGA, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the NGA to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The Energy Policy Act of 2005 (“EPAct 2005”) gives FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act of 1978 of more than $1.2 million per day, per violation. The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements for natural gas sales and purchases described below.
FERC regulations require that any market participant, including a producer, that engages in certain wholesale sales or purchases of natural gas that equal or exceed $2.2 million MMBtus of physical natural gas in the previous calendar year, issue an annual report of such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize or contribute to the formation of price indices. Not all types of natural gas sales are required to be reported on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance provided in FERC orders and other precedent. This reporting requirement is intended to increase the transparency of the wholesale natural gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.
Our ability to transport and sell oil, condensate and NGLs is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act, and intrastate pipeline transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by the FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in
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the cost of transportation service on liquids pipelines. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. However, we do not believe that these regulations affect us any differently than other crude oil, condensate and NGL producers.
Further, interstate and intrastate common carrier liquids pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When liquids pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to pipeline transportation services generally will be available to us to the same extent as to other crude oil, condensate and NGL producers with which we compete.
In addition to FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation.
Regulation of Environmental and Occupational Safety and Health Matters
Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and the protection of the environment and natural resources (including threatened and endangered species and their habitat). Numerous governmental entities, including the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and on-going operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Continued compliance with existing requirements is
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not expected to materially affect us. However, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.
The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Wastes
The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of 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 and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. 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. We generate materials in the course of our operations that may be regulated as hazardous substances.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
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Water Discharges
The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The EPA and the U.S. Army Corps of Engineers have issued final rules attempting to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”) to conform to the definition of the waters of the United States Supreme Court in Sacket v. Environmental Protection Agency, 143 S.Ct 1322 (2023), but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals. However, as a result of ongoing litigation concerning a January 2023 rule concerning WOTUS, several states are enjoined from following this new rule. As a result, substantial uncertainty exists with respect to future implementation of the WOTUS rule.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.
Subsurface Injections
In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near belowground disposal wells used for the injection of oil and natural gas related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies as well as the owners of underground injection wells. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may
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reduce our profitability; however, these costs are commonly incurred by all oil and natural gas producers, and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.
Air Emissions
The CAA and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Recently, there has been increased regulation with respect to air emissions resulting from the oil and natural gas sector. For example, the EPA promulgated rules in 2012, 2016 and 2024 under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil and natural gas production and processing activities pursuant to the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) program. Regarding production activities, these final rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further requires that a subset of these selected wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels.
On March 8, 2024 the EPA published the latest version of final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s final rule include the NSPS to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on VOC emissions to sources that were unregulated under the previous NSPS at Subpart OOOO, process pumps at compressor stations and storage facilities. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. Also, this rulemaking seeks to phase out venting and flaring from well production sites. The effectiveness date of this rule is May 7, 2024 with phased in deadlines for certain sections of the rule. Several states and industry groups have filed suit before the D.C. Circuit challenging the EPA’s implementation of the methane rule and legal authority to issue the methane rules. Texas et al. v. EPA et al., No. 24-1054 (D.C. Cir). On April 12, 2024, the states filed a motion to stay the effectiveness in the rule which is pending.
In addition to the EPA methane rules, on April 10, 2024 the BLM published the Waste Prevention, Production Subject to Royalties, and Resource Conservation rule that seek to limit methane emissions from exploration and production activities on federal lands through limitations on venting and flaring of natural gas, a process whereby operators will pay a royalty for any gas that is avoidably wasted, and requirements for the implementation of leak detection and repair programs for certain processes and equipment. This rule becomes effective on June 10, 2024 with a phased in approach provided for certain sections of the rule. As a result, substantial uncertainty exists with respect to the implementation of both the EPA and BLM methane rules. The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In addition, in October 2015, the EPA issued a final rule under the CAA, lowering the NAAQS for ground level ozone from the current standard
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of 75 ppb for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. The final rule became effective on December 28, 2015. States are expected to implement more stringent permitting and pollution control requirements as a result of this new final rule, which could apply to our operations. The final rule became effective on December 28, 2015. On December 20, 2020, the EPA retained the existing 70 ppb for both standards in its 5-year NAAQS review. Since the effectiveness of the 2015 ozone Standard, states have been submitting revisions to their State Implementation Plans (“SIPS”) to meet or maintain compliance with the 2015 ozone standard.
Compliance with one or more of these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant.
Regulation of GHG Emissions
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified large, GHG emission sources in the United States, including certain onshore and offshore oil and natural gas production sources, which include certain of our operations. As discussed above, federal regulatory action with respect to GHG emissions from the oil and natural gas sector has focused on methane emissions; however, implementation of the federal methane rules is uncertain at this time.
From time to time, Congress has considered legislation to reduce emissions of GHGs, but no significant legislation has been adopted. In the absence of substantive federal climate legislation, a number of states have taken action. State and/or regional cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement entered into force on November 4, 2016 upon achieving its threshold for ratification by signatory countries. A long-term goal of this Paris Agreement is to limit global warming to below two degrees Celsius by 2100 from temperatures in the pre-industrial era. However, the Paris Agreement does not impose any binding obligations on its participants. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement but may enter into a future international agreement related to GHGs. On November 4, 2019, President Trump submitted the formal notification of the United States’ withdrawal of the Parish Agreement to the United Nations. The effective date of the withdrawal was November 4, 2020. However, on January 20, 2021, President Biden signed the instrument for the United States to rejoin the Paris Agreement. On February 19, 2021, the United States officially became a party to the agreement.
Although it is not possible at this time to predict how new laws or regulations in the United States that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.
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Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.
Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published final CAA regulations in 2012 and, more recently, in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting; published in June 2016 an effluent limited guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding TSCA reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in March 2015, the BLM adopted rules establishing stringent standards relating to hydraulic fracturing on federal and American Indian lands. In June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked congressional authority to promulgate the rule; however, this ruling has been appealed and a final decision remains pending. However, the President issued an executive order in March 2017 directing the BLM to review and, if the agency’s review determines that the BLM rule is not consistent with the order’s goal of goal of promoting clean and safe development of energy resources while avoiding unnecessary regulatory burdens, initiate a new rulemaking to repeal or revise the rule. In May 2017, the BLM asked the U.S. Tenth Circuit Court of Appeals to hold in abeyance the litigation surrounding the BLM hydraulic fracturing rules while the agency reconsiders the rules. The Tenth Circuit declined to do so and heard oral arguments in State of Wyoming et al. v. Jewell et. al on July 27, 2017. On July 25, 2017, the BLM initiated a rulemaking to rescind the final rule and reinstate the regulations that existed immediately before the effective date of the rule. In light of the BLM’s proposed rulemaking, on September 21, 2017, the Tenth Circuit dismissed the appeal and remanded with directions to vacate the lower court’s opinion, leaving the final rule in place. On December 29, 2017, the BLM published a final rule formally rescinding the 2015 hydraulic fracturing rule and “return[ing] the affected sections of the [CFR] to the language that existed immediately before the published effective date of the 2015 rule” (in relevant part). 82 Fed. Reg. 61924 (Dec. 29, 2017). In the preamble to the final rule, the BLM explained that the rescission of the 2015 rule was “needed to prevent the unnecessarily burdensome and unjustified administrative requirements and compliance costs of the 2015 rule from encumbering oil and gas development on Federal and Indian lands.” Litigation ensued over the BLM’s rescission of its 2015 rule. The United States District Court for the Northern District of California upheld the BLM’s rescission of the 2015 rule; the district court’s decisions on this were appealed to the Ninth Circuit. The Ninth Circuit litigation was administratively closed in March of 2021 following a February 2021 mediation conference; the litigation continues to be administratively closed.
Several governmental reviews are underway that focus on environmental aspects of hydraulic fracturing activities. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.
From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, the regulation of hydraulic fracturing has continued at the state level. For example, Wyoming, where
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we operate, has promulgated rules related to the public disclosure of substances used in hydraulic fluid, testing requirements for water wells near drilling sites, and leak detection and repair requirements for fugitive emissions from oil and gas production facilities.
In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
At the state level, Wyoming, where we conduct operations, has adopted regulations that impose new or more stringent disclosure, monitoring, and groundwater testing requirements associated with hydraulic fracturing and drilling operations in general. However, states could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective cities’ limits in 2012-2013 but, since that time, local district courts have struck down the ordinances for certain of those Colorado cities in 2014, which decisions were upheld by the Colorado Supreme Court in May 2016. Notwithstanding attempts at the local level to prohibit hydraulic fracturing, there exists the opportunity for cities to adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities. It is also possible the Conservation Commission could pursue more stringent policies or rules and the Wyoming state legislature may seek to adopt new legislation relating to oil and natural gas operations, including measures that would give local governments in Wyoming greater authority to limit hydraulic fracturing and other oil and natural gas operations or require greater distances between wells sites and occupied structures.
Compliance with existing laws and regulations has not had a material adverse effect on our operations or financial position, but if states or localities adopt more stringent restrictions or prohibitions that limit oil and natural gas production and development in the areas where we operate, including, among other things, the development of increased setback distances, we and similarly situated oil and natural exploration and production operators in the state may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we and similarly situated companies operate are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
Activities on Federal Lands
We conduct oil and natural gas exploration, development and production activities on federal lands, including lands administered by the BLM and in some cases, United States Forest Service. Operations on federal lands are frequently subject to permitting delays. Operations on these lands are also subject to the National Environmental Policy Act (“NEPA”) which requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. While we currently have exploration, development and production activities on federal lands, our proposed exploration, development and production activities are expected to include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the procedural requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial.
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Endangered Species and Migratory Birds Considerations
The federal Endangered Species Act (“ESA”), and comparable state laws protect endangered and threatened species. Pursuant to the ESA, if a species is classified as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migrating birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases. In addition, the federal government has in the past issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
Occupational Safety & Health Administration
We are subject to the requirements of the Occupational Safety & Health Administration (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.
Human Capital Resources
As of June 30, 2024, we employed 26 people, all of which were full-time employees. From time to time, we utilize the services of independent contractors to perform various field and other services. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.
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We aim to provide a safe, healthy, respectful, and fair workplace for all employees. We believe our employees’ talent and wellbeing is foundational to delivering on our corporate strategy, and that intentional human capital management strategies enable us to attract, develop, retain and reward our dedicated employees. The health, safety, and well-being of our employees is of the utmost importance.
Facilities
Our principal executive office is located at 1910 Main Avenue, Durango, Colorado 81301, and our telephone number at that address is (970) 247-1500. We also maintain an office in Denver, Colorado.
Legal Proceedings
We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition. Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of these other pending litigation matters, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
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We are managed and operated by our general partner, which is managed by the Board and executive officers of our general partner. The members of our general partner are members of our executive management team, members of our board, some of whom are also affiliated with Yorktown, and other individuals affiliated with Yorktown. Our unitholders will not be entitled to elect our general partner or the Board or otherwise directly participate in our management or operations. Our general partner owes certain contractual duties to us as well as to its members. Upon the closing of this offering, we expect that our general partner will have six directors. At least two of the directors will be independent as defined under the standards established by the Exchange Act and the applicable exchange rules. The NYSE American does not require a listed publicly traded limited partnership, such as ours, to have a majority of independent directors on the Board or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the Exchange Act and the applicable exchange rules, subject to certain transitional relief during the one-year period following consummation of this offering. We will have at least two independent members of the audit committee by the date our Class A Common Units first start trading.
Our operations will be conducted through, and our assets will be owned by, various subsidiaries. However, we will not have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring personnel or by obtaining services of personnel employed by third parties, but we sometimes refer to these individuals, for drafting convenience only, in this prospectus as our employees because they provide services directly to us.
Following the consummation of this offering, our general partner will not receive any management fee or other compensation in connection with our general partner’s management of our business, but we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf and our general partner will hold a participating interest that will entitle it to 10% of the amount of the quarterly Class A Common Unit distribution in excess of our initial target quarterly distribution. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, benefits, bonus, long term incentives and other amounts paid to persons who perform services for us or on our behalf. Please read “Certain Relationships and Related Party Transactions.”
In evaluating director candidates, our general partner will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the Board to fulfill their duties.
Directors and Executive Officers
The following table sets forth certain information regarding the individuals who are expected to constitute the executive officers and directors of our general partner upon consummation of this offering:
Name | Age | Position | ||||
Jack E. Vaughn | 79 | Chief Executive Officer and Chairman of the Board | ||||
Glen E. Christiansen | 55 | President and Chief Operating Officer | ||||
Justin M. Vaughn | 51 | Executive Vice President and Chief Financial Officer | ||||
Ali A. Kouros | 45 | Executive Vice President, Corporate Development and Strategy and Director | ||||
Bryan H. Lawrence | 81 | Director | ||||
Bryan R. Lawrence | 57 | Director | ||||
Greg J. LeBlanc | 53 | Director Nominee | ||||
Paul A. Vermylen, Jr. | 76 | Director Nominee | ||||
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Jack E. Vaughn—Chairman of the Board, Chief Executive Officer. Jack E. Vaughn is our Chief Executive Officer and will serve as the Chairman of the Board. Mr. Vaughn is the founder of Peak E&P and has served as the Chairman of the board of directors and the Chief Executive Officer of Peak E&P since its formation in March 2011. Mr. Vaughn has almost 50 years of experience in the exploration and production industry. From 2002 to 2011, Mr. Vaughn was the Chairman of the board of directors and Chief Executive Officer for three prior iterations of Peak E&P with projects in the Granite Wash in the Texas Panhandle, the Barnett Shale in the Ft. Worth Basin, and in the Bakken Formation in the Williston Basin of North Dakota. Prior to forming Peak E&P, Mr. Vaughn served as the Vice President–Rocky Mountain Division for EnerVest Management Partners Ltd. from 1996 to 2002. Mr. Vaughn also managed a successful San Juan Basin coal bed methane project owned by an EnerVest Management Partners Ltd. and GE Capital Oil & Gas partnership and later sold to Texaco Inc. in November 2001. Before that, Mr. Vaughn was an Executive Project Manager for the Hillman Company Energy Group, where he managed the development of a successful CBM project in the San Juan Basin from 1989 to 2002. Prior to that time, Mr. Vaughn worked as a consultant in drilling and completion operations and project management throughout the Rockies, East Texas, and the Mid-Continent for a number of independents. Mr. Vaughn started his career in 1968 with Amoco Oil Company. Mr. Vaughn also served as member of the board of directors for Bonanza Creek Energy, Inc., the predecessor of Civitas Resources, Inc., from April 2017 until its acquisition by Civitas in April 2021. Mr. Vaughn holds a B.S. in Petroleum Engineering from the University of Texas at Austin. Mr. Vaughn is the father of Justin M. Vaughn, our Chief Financial Officer.
We believe that Mr. Vaughn’s industry experience and deep knowledge of our business make him well suited to serve as a member of our Board.
Glen E. Christiansen—President, Chief Operating Officer. Glen E. Christiansen is our President and Chief Operating Officer and has served as the President of Peak E&P since July 2012 and as its Chief Operating Officer since September 2017. Mr. Christiansen joined Peak E&P in March 2011. Mr. Christiansen has nearly 30 years of experience in the upstream exploration and production industry. In addition to his duties as President and Chief Operating Officer, Mr. Christiansen continues to oversee our geologic operations, identifying and evaluating potential prospects. Prior to joining Peak E&P, Mr. Christiansen was the Rocky Mountain Geology Manager at ExxonMobil/XTO Energy in Fort Worth, Texas, where he was employed for eight years and was involved in multiple unconventional resource plays and acquisitions throughout the Rocky Mountain region including coal bed methane, tight gas, and tight oil. Mr. Christiansen spent eight years with Burlington Resources in Farmington, New Mexico working various plays, primarily in the San Juan Basin. Mr. Christiansen holds a B.S. in geology from Oklahoma State University and a M.S. in geology from University of Wyoming.
Justin M. Vaughn—Executive Vice President and Chief Financial Officer. Justin M. Vaughn is our Executive Vice President and Chief Financial Officer and has served as the Chief Financial Officer of Peak E&P since September 2013, after previously serving as the Vice President of Partner Relations, where he was responsible for interacting and communicating with Peak E&P’s various investment partners, maintaining the company’s financial model, conducting comprehensive financial analyses of various investment opportunities and preparing investment presentations. Mr. Vaughn has over 25 years of financial analysis and investor relations experience. Prior to joining Peak E&P, Mr. Vaughn was the Chief Financial Officer of a privately-held real estate venture in Denver, Colorado and worked for two publicly-traded companies in business development. He also previously worked for PricewaterhouseCoopers in the Business Regeneration Services consulting department. Mr. Vaughn holds a B.A. in Economics from Doane College and an M.B.A. from the University of Denver. Additionally, Mr. Vaughn obtained an Executive Development certificate from the Kellogg School of Management at Northwestern University. Mr. Vaughn is the son of Jack E. Vaughn, the Chairman of the Board and our Chief Executive Officer.
Ali A. Kouros—Executive Vice President, Corporate Development and Strategy and Director. Ali A. Kouros is our Executive Vice President, Corporate Development and Strategy who leads corporate development and strategy. Mr. Kouros has more than 20 years of energy industry experience, which includes 15 years of energy private equity investing. Mr. Kouros began serving as Yorktown’s senior advisor to the Company in 2023
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and helped to formulate and execute its initial public offering strategy. Prior to his advisor role with the Company, he served in a similar capacity for Jefferies & Co., in connection with a spin out of Vitesse Energy, LLC (“Vitesse Energy”) on the New York Stock Exchange from 2020 to 2023. Prior to his role with Vitesse Energy from 2016 to 2019, he invested in energy at Blackstone’s Tactical Opportunities funds and EIG Global Energy Partners. Prior to his role at EIG Global Energy Partners, he was an energy banker at Jefferies & Co. Mr. Kouros started his career as a petroleum engineer at Sabco Oil and Gas company. Mr. Kouros holds a B.S. in Petroleum and Geosystems Engineering from the University of Texas at Austin and a Masters in Finance from Tulane University.
We believe that Mr. Kouros’s industry experience, advising ability and deep knowledge of our business make him well suited to serve as a member of our Board.
Bryan H. Lawrence—Director. Mr. Lawrence is the founder and senior manager of Yorktown, which for over 25 years has managed private equity partnerships that have made investments in companies engaged in the energy industry. Mr. Lawrence was employed with the investment firm of Dillion, Read & Co. Inc. (“Dillion Read”) from 1966 to 1997, serving most recently as a Managing Director until Dillion Read merged with SCB Warburg in September 1997. Mr. Lawrence also serves as a director of other publicly traded companies Ramaco Resources, Inc., Riley Exploration Permian, Inc., Hallador Energy Company and Kestrel Heat LLC (“Kestrel”), the general partner of Star Group, L.P., as well as other non-public companies in the energy industry in which Yorktown holds equity interests. Mr. Lawrence is a graduate of Hamilton College and holds an M.B.A. from Columbia University. Mr. Lawrence is the father of Bryan R. Lawrence, a director nominee.
We believe that Mr. Lawrence’s industry experience and leadership and deep knowledge of our business make him well suited to serve as a member of our Board.
Bryan R. Lawrence—Director. Mr. Lawrence is the founder of Oakcliff Partners LLC, which for 20 years has managed investments in publicly-traded securities. He is also a member of Yorktown, which for over 25 years has managed private equity partnerships that have made investments in companies engaged in the energy industry. He has served on multiple boards of private oil and gas companies. Mr. Lawrence holds a B.A. from Yale University, an M.Phil from University of Cambridge and an M.B.A. from Harvard Business School. Mr. Lawrence is the son of Bryan H. Lawrence, a director.
We believe that Mr. Lawrence’s industry experience and leadership and deep knowledge of our business make him well suited to serve as a member of our Board.
Greg J. LeBlanc—Director Nominee. Greg J. LeBlanc retired as a partner and Senior Vice President in 2020 after 26 years from Wellington Management LLC, one of the world’s largest investment management organizations. In this role, Mr. LeBlanc was responsible for investment analysis and portfolio management of energy and commodity portfolios and served as the energy sector team leader for over a decade. During his tenure, he managed a variety of long only portfolios, hedge funds, as well as sleeves of diversified research and inflation hedging portfolios. Mr. LeBlanc served as a sector specialist for a private equity fund and was heavily involved in applying the firm’s ESG effort to the natural resource sector. His responsibilities encompassed the entire sector covering Exploration and Production, Major Integrated Oils, Master Limited Partnerships, Oil Service and Alternative Energy. During 2012 through 2013 Mr. Leblanc worked in Asia in Wellington Management LLC’s Singapore office to work more closely with team members in the region and help build business. Prior to Wellington, Mr. Leblanc worked at State Street Bank in Boston. Mr. Leblanc graduated from Bates College in 1992 and holds the CFA designation.
We believe that Mr. LeBlanc’s industry experience and breadth of financial knowledge make him well suited to serve as a member of our Board.
Paul A. Vermylen, Jr.—Director Nominee. Mr. Vermylen is the Chairman and a member of the board of directors of Kestrel. Mr. Vermylen has been the chairman and a member of the board of Kestrel since April 2006.
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Mr. Vermylen is a founder of Kestrel and has served as its President and as a manager since July 2005. Mr. Vermylen has been employed since 1971, serving in various capacities, including as a Vice President of Citibank N.A. and Vice President-Finance of Commonwealth Oil Refining Co. Inc. Mr. Vermylen served as Chief Financial Officer of Meenan Oil Co., L.P. (“Meenan”) from 1982 until 1992 and as President of Meenan until 2001, when Kestrel acquired Meenan. Since 2001, Mr. Vermylen has pursued private investment opportunities. Mr. Vermylen is a graduate of Georgetown University and has an M.B.A. from Columbia University.
Mr. Vermylen’s substantial experience on the board of Kestrel and his leadership skills and experience as an executive officer of Meenan, among other factors, led the Board to conclude that he should serve as a member of our Board.
Reimbursement of Expenses of Our General Partner
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
Upon the closing of this offering, we expect our general partner to have a six-member board of directors.
In evaluating director candidates, the members of our general partner will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the Board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the Board to fulfill their duties.
Our general partner’s directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.
Our independent directors will meet the independence standards established by the exchange listing rules, and the Exchange Act.
Committees of the Board of Directors
The Board will have an audit committee and such other committees as the Board shall determine from time to time. The NYSE American listing rules do not require a listed limited partnership to establish a compensation committee or a nominating and corporate governance committee.
Audit Committee
We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the applicable exchange listing rules and the Exchange Act, subject to certain transitional relief during the one-year period following the consummation of this offering. The audit committee will assist the Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will operate under a written charter that satisfies the applicable standards of the SEC and the applicable exchange. The audit committee will have the sole authority to (1) retain and terminate our independent
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registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management. Effective upon the consummation of this offering, will serve on the audit committee. will serve as chair of the audit committee.
Conflicts Committee
In accordance with the terms of our partnership agreement, we may have a conflicts committee consisting of at least two members of the Board to review specific matters that may involve conflicts of interest. The members of our conflicts committee, if any, cannot be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE American and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee cannot own any interest in our general partner or its affiliates or any interest in us or our subsidiaries other than common units or awards, if any, under our incentive compensation plan. We do not expect to have a conflicts committee at the consummation of this offering, but may establish one in the future. Please read “Conflicts of Interest and Duties.”
Board Leadership Structure
Leadership of our general partner’s board of directors is vested in a Chairman of the Board. Mr. Jack Vaughn currently serves as Chief Executive Officer, a Director and the Chairman of the Board, and we have no policy with respect to the separation of the offices of chairman of the Board and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the Board are designated or elected by the members of the general partner. Accordingly, unlike holders of common stock in a corporation, our limited partners (including the Class A Common Unitholders) will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.
Board Role in Risk Oversight
The Board is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.
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EXECUTIVE COMPENSATION AND OTHER INFORMATION
We do not directly employ any of the persons responsible for managing our business. Our general partner’s executive officers will manage our business as part of the services provided by our general partner to us under our partnership agreement. Although all of the employees that conduct our business are either employed by our general partner or its subsidiaries, we sometimes refer to these individuals in this prospectus as our employees.
All of our general partner’s executive officers and other employees necessary to operate our business will be employed and compensated by either our general partner or a subsidiary of the general partner, subject to reimbursement by our general partner. The compensation for all of our executive officers will be indirectly paid by us to the extent provided for in the partnership agreement because we will reimburse our general partner for compensation it pays related to management of our business. Please see “Certain Relationships and Related Party Transactions— Distribution and Payments to Our General Partner and Its Affiliates.”
Our board will have responsibility for reviewing the compensation of our chief executive officer and determining the compensation of our other executive officers. Our predecessor historically compensated certain of its executive officers primarily with base salary and cash bonuses. However, in connection with this offering, the board may consider the compensation structures and levels that they believe will be necessary for executive recruitment and retention for us as a public company.
Emerging Growth Company Status
We are currently considered an “emerging growth company,” within the meaning of the Securities Act, for purposes of the SEC’s executive compensation disclosure rules. In accordance with these rules, we are required to provide a Summary Compensation Table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Furthermore, our reporting obligations extend only to our “named executive officers,” who are the individuals who served as our principal executive officer during 2023 and our next two most highly compensated executive officers at the end of 2023. Accordingly, our “Named Executive Officers” for 2023 are:
Name | Principal Position | |
Jack E. Vaughn | Chief Executive Officer and Chairman of the Board | |
Glen E. Christiansen | President and Chief Operating Officer | |
Justin M. Vaughn | Executive Vice President and Chief Financial Officer |
This discussion may contain forward-looking statements that are based on our current plans, considerations, expectations and determinations regarding future compensation programs. Actual compensation programs that we adopt in the future may differ materially from the currently planned programs summarized in this discussion.
2023 Summary Compensation Table
The following table summarizes the compensation awarded to, earned by or paid to our Named Executive Officers for the fiscal year ended December 31, 2023.
Name and Principal Position | Year | Salary ($)(1) | Bonus ($)(2) | All Other Compensation ($)(3) | Total ($) | |||||||||||||||
Jack E. Vaughn Chief Executive Officer and Chairman of the Board | 2023 | |||||||||||||||||||
Glen E. Christiansen President and Chief Operating Officer | 2023 | |||||||||||||||||||
Justin M. Vaughn Executive Vice President and Chief Financial Officer | 2023 | |||||||||||||||||||
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| (1) | Salary amounts shown in this column represent actual salary earned during the year, reported as gross earnings (i.e., gross amounts before taxes and applicable payroll deductions). |
| (2) | The amounts in this column represent discretionary short-term cash incentive awards paid for 2023. Bonus amounts were determined as more specifically discussed under “—Narrative Disclosure to Summary Compensation Table — Annual Bonuses.” |
| (3) | The amounts in this column reflect Peak E&P’s matching contributions to Peak E&P’s 401(k) plan and the dollar value life insurance premiums paid by Peak E&P for the benefit of each of our Named Executive Officers. In addition, the amount in this column reported for Jack E. Vaughn includes the value attributable to Mr. Vaughn’s personal use of a Peak E&P owned car. |
Narrative Disclosure to Summary Compensation Table
No Employment Agreements and/or Offer Letters
We have not entered into any employment agreement, offer letter or similar employment contract with any of our Named Executive Officers. It is anticipated, however, that we will enter into employment agreements with each of the Named Executive Officers prior to the consummation of this offering.
Base Salary
Each Named Executive Officer’s base salary is a fixed component of compensation for performing specific job duties and functions. Base salaries historically have been generally set at levels deemed necessary to attract and retain individuals with superior talent commensurate with their relative expertise and experience.
Annual Bonuses
Annual cash bonuses are used to motivate and reward our executives and other employees. The annual bonuses paid to our Named Executive Officers for the year ended December 31, 2023 were discretionary bonuses not linked to any performance metrics of the Company or otherwise. For 2023, annual bonuses for our Named Executive Officers were paid in January 2024.
Outstanding Equity Awards at 2023 Year-End
No Named Executive Officer held an outstanding equity award as of December 31, 2023.
Our general partner intends to adopt the Peak Resources LP Long-Term Incentive Plan (the “LTIP”) under which our general partner may issue long-term equity based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards will be intended to compensate the recipients thereof based on the performance of our Class A Common Units and their continued service during the vesting period, as well as to align their long-term interests with those of our Class A Common Unitholders. We will be responsible for the cost of awards granted under the LTIP and all determinations with respect to awards to be made under the LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following description reflects the terms that are currently expected to be included in the LTIP.
General
The LTIP will provide for the grant, from time to time at the discretion of the board of directors of our general partner or any delegate thereof, subject to applicable law, of restricted units, phantom units and distribution equivalent rights. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with
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the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards, subject to proportionate adjustment in the event of unit splits and similar events. Class A Common Units subject to awards that are cancelled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the Class A Common Units will be available for delivery pursuant to other awards.
Restricted Units and Phantom Units
A restricted unit is a Class A Common Unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a Class A Common Unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a Class A Common Unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the plan administrator, cash equal to the fair market value of a Class A Common Unit. The plan administrator of the LTIP may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the plan administrator may determine are appropriate, including the period over which restricted units or phantom units will vest. The plan administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.
Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.
Distribution Equivalent Rights
The plan administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, or additional restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.
Source of Class A Common Units
Class A Common Units to be delivered with respect to awards may be newly-issued Class A Common Units, Class A Common Units acquired by us or our general partner in the open market, Class A Common Units already owned by our general partner or us, Class A Common Units acquired by our general partner directly from us or any other person or any combination of the foregoing.
Anti-Dilution Adjustments and Change in Control
If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the plan administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the plan administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the plan administrator of the LTIP shall have discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, upon any such event, including a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the plan administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) require awards to be surrendered in exchange for
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a cash payment or substitute other rights or property for the award, (iii) provide for the award to assumed by a successor or one of its affiliates, with appropriate adjustments thereto, (iv) cancel unvested awards without payment or (v) make other adjustments to awards as the plan administrator deems appropriate to reflect the applicable transaction or event.
Termination of Service
The consequences of the termination of a grantee’s membership on the board of directors of our general partner or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.
Amendment or Termination of Long-Term Incentive Plan
The plan administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the Class A Common Units for which a grant has not previously been made. The plan administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Internal Revenue Code.
IPO LTIP Awards
In connection with the consummation of this offering, we may grant awards of restricted Class A Common Units (“Restricted Units”) with distribution equivalent rights under the LTIP to certain key employees who provide services to us, including certain of our executive officers. The Restricted Units are being made to reward each recipient for their service in connection with this offering and to align the recipient’s interests with those of our unitholders. It is anticipated that an aggregate of Restricted Units will be granted in connection with this offering (with an aggregate value of approximately $ ), which will include Restricted Units to be granted to our Named Executive Officers.
Additional Narrative Disclosure
Retirement Benefits
We maintain a qualified 401(k) retirement savings plan for all eligible employees, including our Named Executive Officers, which allows participants to defer a percentage of cash compensation up to the maximum amount allowed under Internal Revenue Service Guidelines. We make discretionary matching contributions to our 401(k) plan, generally equal to 100% of up to 6% of the employee’s salary deferred. 401(k) plan participants are always fully vested with respect to their contributions to the plan. We do not maintain, sponsor or otherwise have any liability with respect to any defined pension plan or nonqualified deferred compensation plan.
Employment Contracts, Termination of Employment, Change-in-Control Arrangements
Upon the earlier of a sale of Peak E&P or the filing of the public S-1, Messrs. Christiansen and Justin M. Vaughn are eligible to receive cash bonuses in amounts equal to $87,000 and $109,500, respectively (the “Special Bonuses”). It is anticipated that these Special Bonuses will become due and will be paid by Peak E&P prior to the completion of this offering. Additionally, while we have not yet determined the applicable amounts, it is anticipated that our Named Executive Officers will receive cash bonuses in connection with the consummation of this offering. Any such bonuses will be paid with proceeds from this offering.
We currently do not have any employment agreements or other plans or arrangements with our executive officers (other than the Special Bonuses) that would result in payments to be made by us to an NEO upon the resignation, retirement or any other termination of an NEO’s employment or upon a change in control.
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The members of our board of directors will not receive compensation for their service as a director of our general partner. Non-employee directors will receive reimbursement for out-of-pocket expenses they incur in connection with attending meetings of the board of directors or its committees. Each director will be indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law. We did not pay any compensation, make any equity awards or non-equity awards to, or pay any other compensation to, any of the non-employee directors in 2023.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of our Class A Common Units and Class B Common Units that, upon the consummation of this offering and the related Reorganization Transactions, will be owned by:
| • | beneficial owners of more than 5% of our Class A Common Units and Class B Common Units; |
| • | each named executive officer, director and director nominees of our general partner; and |
| • | all named executive officers, directors and director nominees of our general partner as a group. |
The table assumes the underwriters’ option to purchase additional Class A Common Units from us is not exercised. The percentage of Class A Common Units and Class B Common Units beneficially owned is based on Class A Common Units and Class B Common Units being outstanding immediately following this offering.
In connection with the Reorganization Transactions prior to this offering, we will enter into a contribution agreement (the “Contribution Agreement”) that will effect the transactions whereby each of the Existing Owners will contribute their respective interests in Peak E&P and PBLM and their respective equity ownership in PSI to us in exchange for various equity interests in us. The Existing Owners that receive Class B Common Units will be entitled to have those interests exchanged for Class A Common Units on a one-for-one basis, subject to certain conversion metrics being satisfied. As a result, the number of Class A Common Units and Class B Common Units listed in the table below correlates to the number of Class A Common Units and Class B Common Units the Existing Owners will own immediately prior to and after this offering but without giving effect to any future conversion of Class B Common Units. See “Description of Our Securities—Conversion of Class B Common Units.”
| Class A Common Units to be Beneficially Owned | Percentage of Class A Common Units to be Beneficially Owned | Class B Common Units to be Beneficially Owned | Percentage of Class B Common Units to be Beneficially Owned | |||||||||||||
Name of Beneficial Owner(1) | ||||||||||||||||
5% Unitholders: | ||||||||||||||||
Yorktown VIII(2)(3) | ||||||||||||||||
Yorktown IX(2)(4) | ||||||||||||||||
Yorktown X(2)(5) | ||||||||||||||||
Yorktown XI(2)(6) | ||||||||||||||||
Harbour Vest Real Assets – Energy Fund II L.P.(7) | ||||||||||||||||
Named Executive Officers, Directors and Director Nominees | ||||||||||||||||
Jack E. Vaughn | ||||||||||||||||
Glen E. Christiansen | ||||||||||||||||
Justin M. Vaughn | ||||||||||||||||
Ali A. Kouros | ||||||||||||||||
Bryan H. Lawrence | ||||||||||||||||
Bryan R. Lawrence | ||||||||||||||||
Greg J. LeBlanc | ||||||||||||||||
Paul A. Vermylen, Jr. | ||||||||||||||||
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| (1) | Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Each of the holders listed has sole voting and investment power with respect to the Class A Common Units or Class B Common Units, as applicable, beneficially owned by the holder unless noted otherwise, subject to community property laws where applicable. Unless otherwise noted, the address for each beneficial owner listed below is 1910 Main Avenue, Durango, Colorado 81301. |
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| (2) | Yorktown VIII, Yorktown IX, Yorktown X, and Yorktown XI, which are investment partnerships managed by Yorktown, will beneficially own approximately % of our outstanding Class A Common Units after this offering (or % of our outstanding Class A Common Units on an as-converted basis as a result of their ownership of Class B Common Units). Upon the consummation of the Reorganization Transactions, the funds affiliated with Yorktown will own approximately % of the outstanding Class B Common Units. The address for Yorktown is 410 Park Avenue, 20th Floor, New York, New York 10022. |
| (3) | Yorktown VIII Company LP is the sole general partner of Yorktown Energy Partners VIII, L.P. Yorktown VIII Associates LLC is the sole general partner of Yorktown VIII Company LP. As a result, Yorktown VIII Associates LLC has the power to vote or direct the vote or to dispose or direct the disposition of the units owned by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP and Yorktown VIII Associates LLC disclaim beneficial ownership of the units held by Yorktown Energy Partners VIII, L.P. in excess of their pecuniary interest therein. The managing members of Yorktown VIII Associates LLC are Bryan H. Lawrence, Peter A. Leidel, Tomas R. LaCosta, W. Howard Keenan, Jr., Robert A. Signorino and Bryan R. Lawrence. Each of the entities described in this footnote and each of the managing members of Yorktown VIII Associates LLC (other than to the extent such entity or person directly holds securities as described herein) may be deemed to beneficially own the units directly or indirectly controlled by such entities or such managing member, but each disclaims beneficial ownership of such units. |
| (4) | Yorktown IX Company LP is the sole general partner of Yorktown Energy Partners IX, L.P. Yorktown IX Associates LLC is the sole general partner of Yorktown IX Company LP. As a result, Yorktown IX Associates LLC has the power to vote or direct the vote or to dispose or direct the disposition of the units owned by Yorktown Energy Partners IX, L.P. Yorktown IX Company LP and Yorktown IX Associates LLC disclaim beneficial ownership of the units held by Yorktown Energy Partners IX, L.P. in excess of their pecuniary interest therein. The managing members of Yorktown IX Associates LLC are Bryan H. Lawrence, Peter A. Leidel, Tomas R. LaCosta, W. Howard Keenan, Jr., Robert A. Signorino and Bryan R. Lawrence. Each of the entities described in this footnote and each of the managing members of Yorktown IX Associates LLC (other than to the extent such entity or person directly holds securities as described herein) may be deemed to beneficially own the units directly or indirectly controlled by such entities or such managing member, but each disclaims beneficial ownership of such units. |
| (5) | Yorktown X Company LP is the sole general partner of Yorktown Energy Partners X, L.P. Yorktown X Associates LLC is the sole general partner of Yorktown X Company LP. As a result, Yorktown X Associates LLC has the power to vote or direct the vote or to dispose or direct the disposition of the units owned by Yorktown Energy Partners X, L.P. Yorktown X Company LP and Yorktown X Associates LLC disclaim beneficial ownership of the units held by Yorktown Energy Partners X, L.P. in excess of their pecuniary interest therein. The managing members of Yorktown X Associates LLC are Bryan H. Lawrence, Peter A. Leidel, Tomas R. LaCosta, W. Howard Keenan, Jr., Robert A. Signorino and Bryan R. Lawrence. Each of the entities described in this footnote and each of the managing members of Yorktown X Associates LLC (other than to the extent such entity or person directly holds securities as described herein) may be deemed to beneficially own the units directly or indirectly controlled by such entities or such managing member, but each disclaims beneficial ownership of such units. |
| (6) | Yorktown XI Company LP is the sole general partner of Yorktown Energy Partners XI, L.P. Yorktown XI Associates LLC is the sole general partner of Yorktown XI Company LP. As a result, Yorktown XI Associates LLC has the power to vote or direct the vote or to dispose or direct the disposition of the units owned by Yorktown Energy Partners XI, L.P. Yorktown XI Company LP and Yorktown XI Associates LLC disclaim beneficial ownership of the units held by Yorktown Energy Partners XI, L.P. in excess of their pecuniary interest therein. The managing members of Yorktown XI Associates LLC are Bryan H. Lawrence, Peter A. Leidel, Tomas R. LaCosta, W. Howard Keenan, Jr., Robert A. Signorino and Bryan R. Lawrence. Each of the entities described in this footnote and each of the managing members of Yorktown XI Associates LLC (other than to the extent such entity or person directly holds securities as described herein) may be deemed to beneficially own the units directly or indirectly controlled by such entities or such managing member, but each disclaims beneficial ownership of such units. |
| (7) | HarbourVest Real Assets Associates II L.P. is the sole general partner of Harbour Vest Real Assets – Energy Fund II L.P. HarbourVest Real Assets Associates II LLC is the sole general partner of HarbourVest |
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| Real Assets Associates II L.P. HarbourVest Partners, LLC is the managing member of HarbourVest Real Assets Associates II LLC. As a result, HarbourVest Partners, LLC has the power to vote or direct the vote or to dispose or direct the disposition of the units owned by HarbourVest Real Assets – Energy Fund II L.P. HarbourVest Real Assets Associates II L.P., HarbourVest Real Assets Associates II LLC and HarbourVest Partners, LLC disclaim beneficial ownership of the units held directly by HarbourVest Real Assets – Energy Fund II L.P. The address for HarbourVest Real Assets – Energy Fund II L.P. is c/o HarbourVest Partners LLC, One Financial Center 44th Floor, Boston, Massachusetts 02111. |
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Upon the consummation of this offering, assuming the underwriters do not exercise their option to purchase additional Class A Common Units, the Existing Owners will own Class A Common Units representing an approximate % limited partner interest in us and the Sponsors will own and control our general partner. The Sponsors will appoint all of the directors of our general partner, which will own a small economic general partner interest in us. These percentages do not reflect any Class A Common Units that may be issued under the long-term incentive plan that our general partner expects to adopt prior to the closing of this offering.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, were not the result of arm’s length negotiations.
| Operational Stage | ||
Distributions of Available Cash to affiliates of our general partner | We make cash distributions to our Class A Common Unitholders, including affiliates of our general partner, pro rata.
Upon completion of this offering, the affiliates of our general partner will own Class A Common Units, representing approximately % of our outstanding Class A Common Units, and would receive a pro rata percentage of the cash distributions that we distribute in respect thereof. In connection with the Reorganization Transactions prior to this offering, certain affiliates of our general partner will own Class B Common Units, representing approximately % of our outstanding Class B Common Units. Our Class B Common Units will be mandatorily convertible (at the election of our general partner) into Class A Common Units on a one-for-one basis, subject to certain conversion metrics being satisfied. | |
Payments to our general partner and its affiliates | Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner and its affiliates for costs and expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. | |
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| Operational Stage | ||
Withdrawal or removal of our general partner | If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into Class A Common Units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.” | |
| Liquidation Stage | ||
Liquidation | Upon our liquidation, the partners, including our general partner and its affiliates with respect to any Class A Common Units, Class B Common Units, or other units then held by our general partner and its affiliates, will be entitled to receive liquidating distributions to the extent we have sufficient liquidating proceeds. Please see “Provisions of Our Partnership Agreement Relating to Cash Distributions—Operating Surplus and Capital Surplus—Distributions of Cash Upon Liquidation.” | |
Agreements with Affiliates in Connection with the Reorganization Transactions
In connection with the closing of this offering, we, our general partner and its affiliates will enter into the various documents and agreements that will affect the Reorganization Transactions. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s length negotiations. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.
Contribution Agreement
In connection with the Reorganization Transactions prior to this offering, we will enter into a Contribution Agreement that will effect the transactions whereby each of the Existing Owners will contribute their respective interests in Peak E&P and PBLM and their respective equity ownership in PSI to us in exchange for various equity interests in us. The number of limited partnership interests in the Partnership being issued will not fluctuate based on our initial public offering price. While we believe this agreement is on terms no less favorable to any party than those that could have been negotiated with an unaffiliated third party, it will not be the result of arm’s length negotiations. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.
Other Transactions with Related Persons
In January 2019, Peak Powder River Resources LLC, a wholly-owned subsidiary of Peak E&P (“PPRR”), entered into a crude oil purchase and transportation agreement with Saddle Butte Pipeline III, LLC (“Saddle Butte”) pursuant to which Saddle Butte gathers and transports a portion of PPRR’s produced oil volumes and earns a transportation fee with respect to those volumes delivered and sold at the outlet of the system. For the twelve months ended December 31, 2023 and 2022, Saddle Butte earned transportation fees related to the transportation of PPRR’s volumes of approximately $0.6 million and approximately $0.8 million, respectively. Certain investment partnerships managed by Yorktown own more than 20% of the outstanding equity in Saddle Butte. In addition, Jack E. Vaughn, our Chief Executive Officer, serves on the board of managers of
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Saddle Butte, Bryan H. Lawrence, a member of our Board, serves on the board of managers of Saddle Butte and Justin M. Vaughn, our Executive Vice President and Chief Financial Officer, owns less than 1% of the outstanding equity in Saddle Butte.
In September 2017, PBLM and Peak Powder River Acquisitions, LLC, a wholly-owned subsidiary of PBLM, entered into the ASA with Peak E&P pursuant to which Peak E&P performs administrative duties associated with PBLM’s properties. For the twelve months ended December 31, 2023 and 2022, PBLM paid Peak E&P $1.2 million each year. We anticipate that the ASA will be terminated upon the consummation of the Reorganization Transactions.
Procedures for Review, Approval or Ratification of Transactions with Related Persons
We expect that the Board will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the Board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the Board any conflict or potential conflict of interest that may arise between the director in his or her personal capacity or any affiliate of the director in his or her personal capacity, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the Board in light of the circumstances, be determined by a majority of the disinterested directors.
If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the Board in accordance with the provisions of our partnership agreement. At the discretion of the Board in light of the circumstances, the resolution may be determined by the Board in its entirety or by approval of the conflicts committee or our Class A Common Unitholders and Class B Common Unitholders voting together as a single class (in each case, other than the general partner and its affiliates).
Upon our adoption of our code of business conduct, we would expect that any executive officer will be required to avoid personal conflicts of interest unless approved by the Board.
Please read “Conflicts of Interest and Duties” for additional information regarding the relevant provisions of our partnership agreement.
The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.
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CONFLICTS OF INTEREST AND DUTIES
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the Sponsors) on the one hand, and us and our limited partners (including holders of Class A Common Units and Class B Common Units), on the other hand. Our general partner has a duty to manage us in a manner that is not adverse to the best interests of the Company. The Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and the methods of resolving conflicts of interest. Our partnership agreement also specifically limits the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee or from our unitholders. There is no requirement under our partnership agreement that our general partner seek the approval of our unitholders for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to our unitholders on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution. In determining whether to refer a matter to our unitholders for approval, our general partner will consider a variety of factors, including the nature of the conflict, the size and dollar amount involved, the identity of the parties involved and any other factors the Board deems relevant in determining whether it will seek approval from the conflicts committee or our unitholders. Whenever our general partner makes a determination to refer or not to refer any potential conflict of interest to the conflicts committee or to seek or not to seek unitholder approval, our general partner is acting in its individual capacity, which means that it may act free of any duty or obligation whatsoever to us or our unitholders and will not be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under applicable law, other than the implied contractual covenant of good faith and fair dealing. For a more detailed discussion of the duties applicable to our general partner, as well as the implied contractual covenant of good faith and fair dealing, please read “—Duties of Our General Partner.”
Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our limited partners if the resolution of the conflict is:
| • | approved by the conflicts committee, which our partnership agreement defines as “special approval”; |
| • | approved by the vote of a majority of the outstanding Class A Common Units and Class B Common Units, voting together as a single class, excluding any Class A Common Units and Class B Common Units owned by our general partner or any of its affiliates; |
| • | determined by the Board to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | determined by the Board to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from our unitholders and our general partner’s board of directors determines that the resolution or course of
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action taken with respect to the conflict of interest satisfies either of the standards set forth in the second and third bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he or she is acting in a manner that is not adverse to the best interests of the partnership or that the determination to take or not to take action meets the specified standard; for example, the person may determine that a transaction is being entered into on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or is “fair and reasonable” to us. In taking such action, such person may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement.
Conflicts of interest could arise in the situations described below, among others:
Agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, are not and will not be the result of arm’s-length negotiations.
Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates that does not receive conflicts committee or unitholder approval, must be determined by the Board to be:
| • | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
Our general partner’s affiliates may compete with us and neither our general partner nor its affiliates have any obligation to present business opportunities to us.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might directly compete with us. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.
Our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest.
Our partnership agreement contains provisions that permissibly modify and reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in a manner not adverse to the best interests of us or our unitholders, other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners at the time our partnership agreement was entered into where the language in our
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partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right or its voting rights with respect to the units it owns, whether to exercise its registration rights, and whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.
We do not have any officers or employees and rely solely on officers and employees of our general partner and its affiliates.
Affiliates of our general partner conduct businesses and activities of their own in which we have no economic interest. There could be material competition for the time and effort of the officers and employees who provide services to our general partner.
Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.
Our partnership agreement:
| • | permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and our general partner has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner; |
| • | provides that our general partner shall not have any liability to us or our limited partners for decisions made in its capacity so long as such decisions are made in good faith; |
| • | generally provides that in a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved (i) the conflicts committee or (ii) our Class A Common Unitholders and Class B Common Unitholders other than our general partner and its affiliates and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest is either on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is “fair and reasonable” to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and |
| • | provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the cases may be, acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal. |
By purchasing a Class A Common Unit, a unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.
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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:
| • | the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for equity interests of the partnership, and the incurring of any other obligations; |
| • | the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; |
| • | the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person; |
| • | the use of our assets (including cash on hand) for any purpose consistent with the terms of our partnership agreement; |
| • | the negotiation, execution and performance of any contracts, conveyances or other instruments; |
| • | the distribution of cash held by the partnership; |
| • | the selection and dismissal of officers, employees and agents, attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring; |
| • | the maintenance of insurance for our benefit and the benefit of our partners and indemnitees; |
| • | the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other entities; |
| • | the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation; |
| • | the indemnification of any person against liabilities and contingencies to the extent permitted by law; |
| • | the entering into of listing agreements with any national securities exchange regarding some or all of the our limited partner interests, or the delisting of some or all of our limited partner interests from, or requesting that trading be suspended on, any such exchange; |
| • | the purchase, sale or other acquisition or disposition of our equity interests, or the issuance of additional options, rights, warrants and appreciation rights relating to our equity interests; |
| • | the undertaking of any action in connection with our participation in the management of any member of the partnership group or a joint venture through which any member of the partnership group conducts its business; and |
| • | the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner. |
Please read “The Partnership Agreement” for information regarding the voting rights of unitholders.
We will reimburse our general partner and its affiliates for expenses.
Pursuant to our partnership agreement, we will reimburse our general partner and its affiliates for costs and expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general
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partner will determine such other expenses that are allocable to us, and our partnership agreement does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. Such reimbursements will be made prior to making any distributions on our Class A Common Units. Please read “The Partnership Agreement—Reimbursement of Expenses.”
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party to such agreements has recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement permits our general partner to limit its or our liability, even if we could have obtained terms that are more favorable without the limitation on liability.
Limited partners have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the limited partners, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of Class A Common Units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of Class A Common Units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
Duties of our General Partner
The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied contractual covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners at the time the partnership agreement was entered into where the language in our partnership agreement does not provide for a clear course of action.
As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and the methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited or restricted by state-law fiduciary standards and to take into account the interests of other parties in addition to or in lieu of our interests when resolving conflicts of interest. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the limited partners because they restrict the remedies available to limited partners for actions that, without those provisions, might constitute breaches of fiduciary duty, as described below and permit
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our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:
| • | the fiduciary duties imposed on general partners of a limited partnership by Delaware law in the absence of partnership agreement provisions to the contrary; |
| • | the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties referenced in the preceding bullet that would otherwise be imposed by Delaware law on our general partner; and |
| • | certain rights and remedies of our limited partners contained in our partnership agreement and the Delaware Act. |
Delaware law fiduciary duty standards | Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner of a Delaware limited partnership to use that amount of care that an ordinarily careful and prudent person would use in similar circumstances and to consider all material information reasonably available in making business decisions. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transaction were entirely fair to the partnership. Our partnership agreement modifies these standards as described below. | |
Partnership agreement modified standards | Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it subjectively believed that the decision was not adverse to our best interests, and our general partner will not be subject to any other standard under our partnership agreement or applicable law, other than the implied contractual covenant of good faith and fair dealing. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation whatsoever to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.
Our partnership agreement generally provides that affiliate transactions and resolutions of conflicts of interest not approved by (i) the conflicts committee or (ii) our Class A Common Unitholders and Class B Common Unitholders other than our general partner or any of its affiliates must be determined by the Board to be:
• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or | |
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• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
If our general partner does not seek approval from (i) the conflicts committee or (ii) our Class A Common Unitholders and Class B Common Unitholders other than our general partner or any of its affiliates, and the Board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.
In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or, our limited partners for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal. | ||
Rights and remedies of limited partners | The Delaware Act favors the principles of freedom of contract and enforceability of partnership agreements and allows our partnership agreement to contain terms governing the rights of our unitholders. The rights of our unitholders, including voting and approval rights and the ability of the partnership to issue additional units, are governed by the terms of our partnership agreement. Please read “The Partnership Agreement.” As to remedies of unitholders, the Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself or herself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. | |
By purchasing Class A Common Units, each Class A Common Unitholder will be deemed to have agreed to be bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “Description of Our Securities—Transfer of Class A Common Units.” This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign our partnership agreement does not render our partnership agreement unenforceable against that person.
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Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers, fiduciaries and trustees to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or these persons acted in bad faith or engaged in intentional fraud or willful misconduct. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was criminal. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the U.S. federal securities laws, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “The Partnership Agreement—Indemnification.”
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The following summary description of our securities does not purport to be complete and is subject to and qualified in its entirety by reference to our partnership agreement. For a more complete understanding of our securities, we encourage you to read carefully this entire prospectus, as well as our partnership agreement, the form of which is included in this prospectus as Appendix A.
The Class A Common Units represent limited partner interests in us. The Class A Common Units will entitle the Class A Common Unitholders to quarterly cash distributions of Available Cash. The Class A Common Unitholders will be entitled to exercise the rights and privileges available to Class A limited partners under our partnership agreement.
Duties
We will retain a third-party entity to serve as registrar and transfer agent for the Class A Common Units. We expect to pay all fees charged by the transfer agent for transfers of Class A Common Units, except the following, which must be paid by our unitholders:
| • | surety bond premiums to replace lost or stolen certificates or to cover taxes and other governmental charges; |
| • | special charges for services requested by unitholders; and |
| • | other similar fees or charges. |
There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of their actions for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the indemnitee.
Resignation or Removal
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.
Transfer of Class A Common Units
By transfer of Class A Common Units in accordance with our partnership agreement, each transferee of Class A Common Units shall be admitted as a limited partner with respect to the Class A Common Units transferred when such transfer and admission are reflected in our books and records. Each transferee:
| • | represents that the transferee has the capacity, power and authority to become bound by our partnership agreement; |
| • | automatically agrees to be bound by the terms and conditions of our partnership agreement; and |
| • | gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering. |
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Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the Class A Common Units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per Class A Common Unit for the 20 consecutive trading days immediately prior to the date set for redemption. Please read “The Partnership Agreement—Non-Citizen Unitholders; Redemption.”
In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred Class A Common Units. Our general partner will cause any transfers to be recorded on our books and records from time to time (or shall cause the transfer agent to do so, as applicable).
The transferor of Class A Common Units will have a duty to provide the transferee with all information that may be necessary to transfer the Class A Common Units. The transferor will not have a duty to ensure the execution of the transfer application and certification by the transferee and will have no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application and certification to the transfer agent.
Until a Class A Common Unit has been transferred on our books and records, we and the transfer agent may treat the record holder of the Class A Common Unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.
We may, at our discretion, treat the nominee holder of a Class A Common Unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
Class A Common Units are securities, and any transfers are subject to the laws governing transfers of securities.
The Class B Common Units represent limited partner interests in us. The Class B Common Units will not be listed on any stock exchange and will not be entitled to quarterly cash distributions; however, each Class B Common Unit will be mandatorily convertible (at the election of our general partner) into one Class A Common Unit based upon an excess Distributable Cash from Operations coverage test, which we intend will protect the existing Class A Common Unitholder distribution. See “—Conversion of Class B Common Units” and “Our Cash Distribution Policy and Restrictions on Distributions.” The Class B Common Unitholders are entitled to exercise the rights and privileges available to Class B limited partners under our partnership agreement. For a description of rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”
Upon the consummation of the Reorganization Transactions, an aggregate of Class B Common Units are expected to be outstanding.
Conversion of Class B Common Units
The Class B Common Units, which have been issued to certain investment partnerships managed by Yorktown, management and other investors who are not affiliated with Yorktown or management, will not receive cash distributions, other than any distribution of Available Cash from capital surplus, distributions of proceeds of the sale of our investment in PSI and any liquidating distributions. The Class B Common Units are
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mandatorily convertible (at the election of our general partner) into Class A Common Units up to an amount such that there is sufficient Distributable Cash from Operations, which would occur when we have generated Distributable Cash from Operations equal to 1.2x the annual cash distribution amount for the four quarters preceding the conversion on the currently outstanding Class A Common Units and the additional Class A Common Units to be issued to the holders of Class B Common Units being converted. The holders of Class B Common Units may assign all or a portion of their right to have the Class B Common Units converted into Class A Common Units to other holders of Class B Common Units. Yorktown intends to assign to certain affiliates of HarbourVest Equity Partners, LLC (“HarbourVest”) who will receive Class B Common Units in exchange for their contribution of preferred units in Peak E&P to the partnership its right to have Class B Common Units converted to Class A Common Units until such HarbourVest entities have had all of their Class B Common Units converted into Class A Common Units, after which time, Yorktown’s Class B Common Units would be converted into Class A Common Units at the election of our general partner.
Our general partner will exercise its discretion with the intent of having sufficient cash available for distribution over the next four quarters to pay the Class A Common Unit distribution on the existing outstanding and converted Class A Common Units.
There can be no assurance, however, that there will be sufficient Distributable Cash from Operations in future periods to maintain or increase the cash distributions on the existing and newly issued Class A Common Units, which could result in a decrease or even elimination of cash distributions on the Class A Common Units.
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The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request, at no charge.
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
| • | with regard to distributions of Available Cash, please read “Our Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions;” |
| • | with regard to the duties of our general partner, please read “Conflicts of Interest and Duties;” |
| • | with regard to the transfer of Class A Common Units, please read “Description of our Securities—Transfer of Class A Common Units”; and |
| • | with regard to tax matters, please read “Material U.S. Federal Income Tax Consequences.” |
Our partnership was organized under Delaware law and will have a perpetual existence unless dissolved, wound up and terminated pursuant to the terms of our partnership agreement and the Delaware Act.
Our purpose under our partnership agreement is to engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law.
Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the ownership, acquisition, exploitation and development of oil, NGL and natural gas businesses and assets, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
Unitholders are not obligated to make additional capital contributions, except as described under “—Limited Liability.”
The following is a summary of the unitholder vote required for each of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of the Class A Common Units and Class B Common Units, including any Class A Common Units and Class B Common Units owned by our general partner, its members and their respective affiliates, voting together as a single class.
In voting their Class A Common Units or Class B Common Units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair
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dealing. The holders of a majority of the Class A Common Units and Class B Common Units (including any Class A Common Units and Class B Common Units deemed owned by our general partner, its members and their respective affiliates), voting together as a single class entitled to vote at the meeting, represented in person or by proxy, shall constitute a quorum at a meeting of common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.
Issuance of additional units | No approval right. Please read “—Issuance of Additional Partnership Interests.” | |
Amendment of the partnership agreement | Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Certain types of amendments require a majority of the holders of the type or class of units affected, or 90% of the outstanding Class A Common Units and Class B Common Units voting together as a single class and on an as-converted basis (including units owned by our general partner and its affiliates) or other voting thresholds. Please read “—Amendment of the Partnership Agreement.” | |
Merger of our partnership or the sale of all or substantially all of our assets | Unit majority in certain circumstances. Please read “—Merger, Consolidation, Sale or Other Disposition of Assets.” | |
Dissolution of our partnership | Unit majority. Please read “—Termination and Dissolution.” | |
Continuation of our business upon certain | Unit Majority. Please read “—Termination and Dissolution.” | |
Withdrawal of our general partner | Prior to , 2034, a majority of our outstanding Class A Common Units and Class B Common Units, voting together as a single class and on an as-converted basis, excluding units held by our general partner and its affiliates, is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. After , 2034, upon 90 days’ notice. Please read “—Withdrawal or Removal of Our General Partner.” | |
Removal of our general partner | For cause with not less than 66 2/3% of our outstanding Class A Common Units and Class B Common Units, voting together as a single class and on an as-converted basis, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.” | |
| Transfer of our general partner interest | Our general partner may transfer any or all of its general partner interest in us without a vote of our unitholders. Please read “—Transfer of General Partner Interest.” | |
| Transfer of ownership interest in our general partner | No unitholder approval required. Please read “—Transfer of Ownership Interests in Our General Partner.” | |
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Applicable Law; Forum, Venue and Jurisdiction
Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:
| • | arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us); |
| • | brought in a derivative manner on our behalf; |
| • | asserting a claim of breach of a duty (including fiduciary duty) owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners; |
| • | asserting a claim arising pursuant to any provision of the Delaware Act; or |
| • | asserting a claim governed by the internal affairs doctrine, |
shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. The foregoing provision will not apply to any claims as to which the Court of Chancery determines that there is an indispensable party not subject to the jurisdiction of such court, which is rested in the exclusive jurisdiction of a court or forum other than such court (including claims arising under the Exchange Act), or for which such court does not have subject matter jurisdiction, or to any claims arising under the Securities Act and, unless we consent in writing to the selection of an alternative forum, the United States federal district courts will be the sole and exclusive forum for resolving any action asserting a claim arising under the Securities Act. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules or regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain such Securities Act claims. To prevent having to litigate claims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, the partnership agreement provides that, unless we consent in writing to the selection of an alternative forum, United States federal district courts shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. There is uncertainty as to whether a court would enforce the forum provision with respect to claims under the federal securities laws.
Our partnership agreement also provides that each limited partner waives the right to trial by jury in any such claim, suit, action or proceeding, including any claim under the U.S. federal securities laws, to the fullest extent permitted by applicable law. No unitholder can waive compliance with respect to the Partnership’s or such unitholder’s compliance with U.S. federal securities laws and the rules and regulations promulgated thereunder. If the partnership or one of the partnership unitholders opposed a jury trial demand based on the waiver, the applicable court would determine whether the waiver was enforceable based on the facts and circumstances of that case in accordance with applicable state and federal laws. To our knowledge, the enforceability of a contractual pre-dispute jury trial waiver in connection with claims arising under the U.S. federal securities laws has not been finally adjudicated by the United States Supreme Court. However, we believe that a contractual pre-dispute jury trial waiver provision is generally enforceable, including under the laws of the State of Delaware, which govern our partnership agreement.
By purchasing a Class A Common Unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other courts in Delaware) in connection with any such claims, suits, actions or proceedings.
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Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he or she otherwise acts in conformity with the provisions of our partnership agreement, his or her liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he or she is obligated to contribute to us for his or her limited partner interests plus his or her share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by our limited partners as a group:
| • | to remove or replace our general partner; |
| • | to approve certain amendments to the partnership agreement; or |
| • | to take other action under the partnership agreement; |
constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under Delaware law, to the same extent as our general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his or her assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
Our operating subsidiaries conduct business in Wyoming and Colorado, among other states, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as an owner of our operating subsidiary may require compliance with legal requirements in the jurisdictions in which our operating subsidiary conducts business, including qualifying our operating subsidiary to do business there.
Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership in our subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.
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Issuance of Additional Partnership Interests
Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders. We can issue an unlimited number of additional units, including units that are senior to the Class A Common Units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders.
It is possible that we will fund acquisitions through the issuance of additional Class A Common Units or other partnership interests. Holders of any additional Class A Common Units we issue will be entitled to share equally with the then-existing holders of Class A Common Units in our distributions of Available Cash. In addition, the issuance of additional Class A Common Units or other partnership interests may dilute the value of the interests of the then-existing holders of Class A Common Units in our net assets.
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting or other rights to which the Class A Common Units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to our Class A Common Units.
Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase Class A Common Units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by Class A Common Units, that existed immediately prior to each issuance. The holders of Class A Common Units will not have preemptive rights to acquire additional Class A Common Units or other partnership interests.
Amendment of the Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. To adopt a proposed amendment, other than the amendments discussed below under “—No Limited Partner Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.
Prohibited Amendments
No amendment may be made that would:
| • | enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or |
| • | enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion. |
The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding Class A
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Common Units and Class B Common Units voting together as a single class and on an as-converted basis (including units owned by our general partner and its affiliates). Upon the consummation of this offering, affiliates of our general partner will own an aggregate of approximately % of our outstanding Class A Common Units and % of our outstanding Class B Common Units, representing an aggregate of approximately % of our outstanding limited partnership units entitled to vote.
No Limited Partner Approval
Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:
| • | a change in our name, the location of our principal place of business, our registered agent or our registered office; |
| • | the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement; |
| • | a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state; |
| • | a change in our fiscal year or taxable year and related changes; |
| • | an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents or trustees of our general partner from being subjected, in any manner, to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor; |
| • | an amendment that sets forth the designations, preferences, rights, powers and duties of any class or series of additional partnership securities or rights to acquire partnership securities, that our general partner determines to be necessary or appropriate or advisable for the authorization or issuance of additional partnership securities or rights to acquire partnership securities; |
| • | any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone; |
| • | an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement; |
| • | any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, limited liability company, joint venture or other entity, as otherwise permitted by our partnership agreement; |
| • | any amendment necessary to require our limited partners to provide a statement, certification or other evidence to us regarding whether such limited partner is subject to United States federal income taxation on the income generated by us and to provide for the ability of our general partner to redeem the units of any limited partner who fails to provide such statement, certification or other evidence; |
| • | an amendment that our general partner determines to be necessary or appropriate or advisable in connection with conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or |
| • | any other amendments substantially similar to any of the matters described in the clauses above. |
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In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:
| • | do not adversely affect our limited partners (or any particular class of limited partners) in any material respect; |
| • | are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute; |
| • | are necessary or appropriate to facilitate the trading of our units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our units are or will be listed for trading; |
| • | are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or |
| • | are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement. |
Opinion of Counsel and Unitholder Approval
For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding Class A Common Units and Class B Common Units, voting together as a single class and on an as-converted basis, unless we first obtain such an opinion.
In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the holders of the type or class of units so affected, but no vote will be required by the holders of any class or classes or type or types of units that our general partner determines are not adversely affected in any material respect. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any amendment that would increase the percentage of units required to remove the general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 66 2/3 of the Class A Common Units and Class B Common Units, voting together as a single class and on an as-converted basis. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than a majority of the Class A Common Units and Class B Common Units voting together as a single class and on an as-converted basis.
Merger, Consolidation, Sale or Other Disposition of Assets
A merger, consolidation, or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation, or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interest of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing.
In addition, our partnership agreement generally prohibits our general partner, without the prior approval of a unit majority, voting together as a single class, from causing us, among other things, to sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries’ assets in a single transaction or a series of related transactions, including by way of merger, consolidation, conversion or other combination or sale of
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ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger, consolidation or conversion without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability matters, the transaction will not result in an amendment to our partnership agreement (other than an amendment that the general partner could adopt without the consent of the other partners), each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.
If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability matters, and the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger, consolidation or conversion, a sale of substantially all of our assets or any other similar transaction or event.
We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:
| • | the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner, other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or a withdrawal or removal followed by approval and admission of a successor; |
| • | the election of our general partner to dissolve us, if approved by a unit majority; |
| • | the entry of a decree of judicial dissolution of our partnership pursuant to the provisions of the Delaware Act; or |
| • | there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law. |
Upon a dissolution under the first bullet above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing a successor general partner, subject to our receipt of an opinion of counsel to the effect that the action would not result in the loss of limited liability under Delaware law of any limited partner.
Liquidation and Distributions of Proceeds
Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Operating Surplus and Capital Surplus—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.
Withdrawal or Removal of Our General Partner
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to , 2034 without obtaining the approval of the holders of at least a majority of our outstanding
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Class A Common Units and Class B Common Units, voting together as a single class and on an as-converted basis, excluding units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability matters. On or after , 2034, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving at least 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw as our general partner without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner to sell or otherwise transfer all of its general partner interest in us without the approval of our unitholders. Please read “—Transfer of General Partner Interest.”
Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability matters cannot be obtained, we will be dissolved, wound up and liquidated. Please read “—Termination and Dissolution.”
Our general partner may not be removed unless that removal is for cause and approved by the vote of the holders of not less than 66 2/3% of our outstanding Class A Common Units and Class B Common Units, voting together as a single class and on an as-converted basis, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of a unit majority. The ownership of more than 33 1/3% of our outstanding Class A Common Units and Class B Common Units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. Upon the consummation of this offering, affiliates of our general partner will own an aggregate of approximately % of our outstanding Class A Common Units and Class B Common Units, representing approximately % of our outstanding Class A Common Units and Class B Common Units.
In the event of removal of our general partner or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and its affiliate and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and its affiliate and the successor general partner will determine the fair market value. If the departing general partner and its affiliate and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into Class A Common Units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.
Transfer of General Partner Interest
Our general partner may transfer all or any of its general partner interest to an affiliate or a third party without the approval of our unitholders. As a condition of this transfer, the transferee must, among other things,
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assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability matters.
Our general partner and its affiliates may at any time transfer Class A Common Units to one or more persons without unitholder approval.
Transfer of Ownership Interests in Our General Partner
At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or a third party without the approval of our unitholders.
Change of Management Provisions
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the management of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the Board.
If at any time our general partner and its affiliates own more than 80% of our then-issued and outstanding limited partner interests of any class, including the Class A Common Units, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:
| • | the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and |
| • | the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed. |
As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have its limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of its common units in the market. Please read “Material U.S. Federal Income Tax Consequences.”
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units of the applicable class on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of
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the number of units necessary to authorize or take such action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, entitled to vote at the meeting represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
Each record holder of a Class A Common Unit or Class B Common Unit (if voting on the matter) has a vote according to his or her percentage interest in the aggregate Class A Common Units or Class B Common Units, voting together as a single class and on an as-converted basis, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates (including the Founders) or a direct or subsequently approved transferee of our general partner or its affiliates or a transferee of that person or group approved by our general partner or a person or group specifically approved by our general partner or the Board, as applicable, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Units held by a nominee or in a street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his or her nominee provides otherwise.
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our partnership agreement will be delivered to the record holder by us or by the transfer agent or an exchange agent.
By transfer of any units in accordance with our partnership agreement, each transferee of units shall be admitted as a limited partner with respect to the units transferred when such transfer and admission is reflected in our books and records. Except as described under “—Limited Liability,” the units will be fully paid, and unitholders will not be required to make additional contributions.
Non-Citizen Unitholders; Redemption
We may acquire interests in oil and natural gas leases on United States federal lands in the future. To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, our general partner, acting on our behalf, may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per Class A Common Unit for the 20 consecutive trading days immediately prior to the date set for redemption. Further, the limited partnership interests held by such unitholder will not be entitled to any voting rights and may not receive distributions in-kind upon our liquidation.
Furthermore, we have the right to redeem all of the units of any holder that our general partner concludes is not an Eligible Holder or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the current market price of such unit (the date of determination of which shall be the date fixed for redemption). The redemption price will be paid, as determined by our general partner, in cash or by delivery of a promissory note. Any such promissory note will
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bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.
For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof.
Under our partnership agreement, unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events,:
| • | our general partner; |
| • | any departing general partner; |
| • | any person who is or was an affiliate of our general partner or any departing general partner; |
| • | any person who is or was a director, officer, manager, managing member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points; |
| • | any person who is or was serving as a director, officer, manager, managing member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and |
| • | any person designated by our general partner. |
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance covering liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner are not subject to any caps or other limits.
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting and tax purposes, our fiscal year is the calendar year.
We will mail or make available to record holders of units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also mail or make available a report containing unaudited financial statements within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.
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We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every unitholder will receive information to assist it in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether such unitholder supplies us with information.
Right to Inspect Our Books and Records
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his or her interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his or her own expense, obtain:
| • | a current list of the name and last known address of each record holder; and |
| • | copies of our partnership agreement and our certificate of limited partnership and related amendments thereto. |
Our general partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any Class A Common Units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. Please read “Class A Common Units Eligible for Future Sale.”
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CLASS A COMMON UNITS ELIGIBLE FOR FUTURE SALE
After the sale of the Class A Common Units offered hereby, the Existing Owners (including investment partnerships managed by Yorktown) will own Class A Common Units, or approximately % of our limited partner interests. Once our Class A Common Units are publicly traded, the sale of Class A Common Units by the Existing Owners in the public markets could have an adverse impact on the price of the Class A Common Units or on any trading market that may develop. In addition, upon completion of the Reorganization Transactions, the Existing Owners will own Class B Common Units, which are mandatorily convertible (at the election of our general partner) into Class A Common based upon an excess Distributable Cash from Operations coverage test. See “Description of Our Securities—Conversion of Class B Common Units.”
The Class A Common Units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any Class A Common Units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
| • | 1% of the total number of the securities outstanding; or |
| • | the average weekly reported trading volume of the Class A Common Units for the four calendar weeks prior to the sale. |
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A unitholder who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his or her Class A Common Units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those Class A Common Units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.
Our Partnership Agreement and Registration Rights
Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our Class A Common Units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Partnership Interests.”
Under our partnership agreement, our general partner and its affiliates, including the Sponsors, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any Class A Common Units and any other partnership interests that they beneficially hold, which we refer to as registerable securities. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any registerable securities to require registration of such registerable securities and to include any such registerable securities in a registration by us of Class A Common Units or other partnership interests, including Class A Common Units or other partnership interests offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of Class A Common Units or other partnership interests held by our general partner or its affiliates, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Except as described below, our general partner and its affiliates may sell their Class A Common Units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.
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We, the Sponsors, our directors and executive officers and the beneficial owners of more than 5% of our Class A Common Units and Class B Common Units have agreed not to sell any of our Class A Common Units or any securities convertible into, exchangeable for, exercisable for, or repayable with our Class A Common Units for a period of 180 days from the date of this prospectus, subject to certain exceptions. For a description of these lock-up provisions, please read “Underwriting.”
Registration Statement on Form S-8
Prior to the completion of this offering, we expect to adopt the LTIP. If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register Class A Common Units issuable under the LTIP. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, Class A Common Units issued under the LTIP will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.
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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES
The following is a summary of the material U.S. federal income tax consequences related to the purchase, ownership and disposition of our Class A Common Units by a taxpayer that holds our Class A Common Units as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations, administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change or differing interpretations, possibly with retroactive effect. We cannot assure you that a change in law will not significantly alter the tax considerations that we describe in this summary. We have not sought any ruling from the Internal Revenue Service (the “IRS”), with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.
This summary does not address all aspects of U.S. federal income taxation. In addition, this summary does not address the Medicare tax on certain investment income, alternative minimum tax, U.S. federal estate or gift tax laws, any state, local or non-U.S. tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):
| • | banks, insurance companies or other financial institutions; |
| • | tax-exempt or governmental organizations; |
| • | qualified foreign pension funds (or any entities all of the interests of which are held by a qualified foreign pension fund); |
| • | tax-qualified retirement plans; |
| • | dealers in securities or foreign currencies; |
| • | traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes; |
| • | persons whose functional currency is not the U.S. dollar; |
| • | “controlled foreign corporations,” “passive foreign investment companies” and corporations that accumulate earnings to avoid U.S. federal income tax; |
| • | partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein; |
| • | persons deemed to sell our Class A Common Units under the constructive sale provisions of the Code; |
| • | persons that acquired our Class A Common Units through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan; |
| • | certain former citizens or long-term residents of the United States; |
| • | real estate investment trusts or regulated investment companies; and |
| • | persons that hold our Class A Common Units as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction. |
If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our Class A Common Units, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, upon the activities of the partnership, and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) investing in our Class A Common Units to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our Class A Common Units by such partnership.
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YOU ARE ENCOURAGED TO CONSULT YOUR TAX ADVISOR WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS (INCLUDING ANY POTENTIAL FUTURE CHANGES THERETO) TO YOUR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON UNITS ARISING UNDER ANY OTHER TAX LAWS, INCLUDING THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.
Although we are a Delaware limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are subject to tax as a corporation and distributions on our Class A Common Units will be treated as distributions on corporate stock for U.S. federal income tax purposes. No Schedule K-1 will be issued with respect to either of our Class A Common Units. Instead, holders of Class A Common Units will receive a Form 1099 from us or a broker with respect to distributions received on our Class A Common Units.
The discussion in this section is addressed to holders of our Class A Common Units who are U.S. holders for U.S. federal income tax purposes. For the purposes of this discussion, a “U.S. holder” is a beneficial owner of our Class A Common Units that, for U.S. federal income tax purposes, is:
| • | an individual who is a citizen or resident of the United States; |
| • | a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia; |
| • | an estate the income of which is subject to U.S. federal income tax regardless of its source; or |
| • | a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person for U.S. federal income tax purposes. |
Distributions
Distributions with respect to our Class A Common Units will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent that the amount of distributions with respect to our Class A Common Units exceed our current and accumulated earnings and profits, such distributions will be treated first as a tax-free return of capital to the extent of the U.S. holder’s adjusted tax basis in such Class A Common Units, which reduces such basis dollar-for-dollar (but not below zero), and thereafter as capital gain from the sale or exchange of such Class A Common Units. See “—Gain on Disposition.” Non-corporate holders that receive distributions on our Class A Common Units that are treated as dividends for U.S. federal income tax purposes generally will be subject to U.S. federal income tax at a reduced rate (currently at a maximum rate of 20%) provided certain holding period requirements are met.
You are encouraged to consult your tax advisor as to the tax consequences of receiving distributions on our Class A Common Units that do not qualify as dividends for U.S. federal income tax purposes, including, in the case of prospective corporate investors, the inability to claim the corporate dividends received deduction with respect to such distributions.
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Gain on Disposition
A U.S. holder generally will recognize capital gain or loss on a sale, exchange, certain redemptions, or other taxable disposition of our Class A Common Units equal to the difference, if any, between the amount realized upon the disposition of such Class A Common Units and the U.S. holder’s adjusted tax basis in those Class A Common Units. A U.S. holder’s tax basis in the Class A Common Units generally will be equal to the amount paid for such Class A Common Units reduced (but not below zero) by distributions received on such Class A Common Units that are not treated as dividends for U.S. federal income tax purposes. Such capital gain or loss generally will be long-term capital gain or loss if the U.S. holder’s holding period for the Class A Common Units sold or disposed of is more than one year. Long-term capital gains of non-corporate U.S. holders generally are subject to U.S. federal income tax at a reduced rate (currently at a maximum rate of 20%). The deductibility of net capital losses is subject to limitations.
Backup Withholding and Information Reporting
Information returns generally will be filed with the IRS with respect to distributions on our Class A Common Units and the proceeds from a disposition of our Class A Common Units. U.S. holders may be subject to backup withholding on distributions with respect to our Class A Common Units and on the proceeds of a disposition of our Class A Common Units unless such U.S. holders furnish the applicable withholding agent with a taxpayer identification number, certified under penalties of perjury, and certain other information, or otherwise establish, in the manner prescribed by law, an exemption from backup withholding. Penalties apply for failure to furnish correct information and for failure to include reportable payments in income.
Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be creditable against a U.S. holder’s U.S. federal income tax liability, and the U.S. holder may be entitled to a refund, provided the U.S. holder timely furnishes the required information to the IRS. U.S. holders are urged to consult their own tax advisors regarding the application of the backup withholding rules to their particular circumstances and the availability of, and procedure for, obtaining an exemption from backup withholding.
Consequences to Non-U.S. Holders
The discussion in this section is addressed to holders of our Class A Common Units who are non-U.S. holders for U.S. federal income tax purposes. For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our Class A Common Units that is an individual, corporation, estate or trust that is not a U.S. holder as defined above.
Distributions
Distributions with respect to our Class A Common Units will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent these distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our Class A Common Units and thereafter as a capital gain from the sale or exchange of such Class A Common Units. See “—Gain on Disposition.”
Subject to the withholding requirements under FATCA (as defined below) and with respect to effectively connected dividends, each of which is discussed below, any distribution made to a non-U.S. holder on our Class A Common Units generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the distribution unless an applicable income tax treaty provides for a lower rate. To the extent a distribution exceeds our current and accumulated earnings and profits, such distribution will reduce the non-U.S. holder’s adjusted tax basis in its Class A Common Units (but not below zero). The amount of any such distribution in excess of the non-U.S. holder’s adjusted tax basis in its Class A Common Units will be treated as gain from the
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sale of such Class A Common Units and will have the tax consequences described below under “—Gain on Disposition.” The rules applicable to distributions by a United States real property holding corporation (a “USRPHC”) to non-U.S. persons that exceed current and accumulated earnings and profits are not clear. As a result, it is possible that U.S. federal income tax at a rate not less than 15% (or such lower rate as may be specified by an applicable income tax treaty for distributions from a USRPHC) may be withheld from distributions received by non-U.S. holders that exceed our current and accumulated earnings and profits. To receive the benefit of a reduced income tax treaty rate, a non-U.S. holder must provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.
Non-U.S. holders are encouraged to consult their tax advisors regarding the withholding rules applicable to distributions on our Class A Common Units, the requirement for claiming income tax treaty benefits, and any procedures required to obtain a refund of any over-withheld amounts.
Distributions treated as dividends that are paid to a non-U.S. holder and that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, such non-U.S. holder may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.
Gain on Disposition
Subject to the discussion below under “—Backup Withholding and Information Reporting,” a non-U.S. holder generally will not be subject to U.S. federal income or withholding tax on any gain realized upon the sale or other disposition of our Class A Common Units unless:
| • | the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or other disposition occurs and certain other conditions are met; |
| • | the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or |
| • | our Class A Common Units constitute United States real property interests by reason of our status as a USRPHC for U.S. federal income tax purposes. |
A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses provided the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses.
A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph, the third bullet point above, generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation for U.S. federal income tax purposes and the gain is described in the second bullet point above, then such gain would also be included in its effectively connected earnings and profits (as adjusted for certain items), which may be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty).
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Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes.
However, as long as our Class A Common Units continue to be “regularly traded on an established securities market” (within the meaning of the applicable U.S. Treasury regulations), only a non-U.S. holder that actually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the Class A Common Units, more than 5% of the fair market value of the Class A Common Units will be treated as disposing of a United States real property interest and will be taxable on gain realized on the disposition of such Class A Common Units as a result of our status as a USRPHC. If our Class A Common Units were not considered to be regularly traded on an established securities market, a non-U.S. holder (regardless of the percentage owned of the Class A Common Units ) would be treated as disposing of a United States real property interest and would be subject to U.S. federal income tax on a taxable disposition of our Class A Common Units, and a 15% withholding tax would apply to the gross proceeds from such disposition.
Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our Class A Common Units, including regarding potentially applicable income tax treaties that may provide for different rules.
Backup Withholding and Information Reporting
Any distributions paid to a non-U.S. holder must be reported annually to the IRS and to each non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Distributions to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form).
Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our Class A Common Units effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our Class A Common Units effected outside the United States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the non-U.S. holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our Class A Common Units effected outside the United States by such a broker if it has certain relationships within the United States.
Backup withholding is not an additional tax. Rather, the U.S. federal income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.
Additional Withholding Requirements under FATCA
Sections 1471 through 1474 of the Code, and the U.S. Treasury regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid on our Class A Common Units and, subject to the proposed U.S. Treasury regulations discussed below, on proceeds from sales or other dispositions of our Class A Common Units, if paid to a “foreign financial institution” or a “non-financial foreign
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entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are non-U.S. entities with U.S. owners), (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS Form W-8BEN-E), or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes.
While gross proceeds from a sale or other disposition of our Class A Common Units paid after January 1, 2019, would have originally been subject to withholding under FATCA, proposed U.S. Treasury regulations provide that such payments of gross proceeds do not constitute withholdable payments. Taxpayers may generally rely on these proposed U.S. Treasury regulations until they are revoked or final U.S. Treasury regulations are issued. Non-U.S. holders are encouraged to consult their own tax advisors regarding the effects of FATCA on an investment in our Class A Common Units.
INVESTORS CONSIDERING THE PURCHASE OF OUR CLASS A COMMON UNITS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS (INCLUDING ANY POTENTIAL FUTURE CHANGES THERETO) TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF ANY OTHER TAX LAWS, INCLUDING U.S. FEDERAL ESTATE AND GIFT TAX LAWS AND ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND TAX TREATIES.
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Janney Montgomery Scott LLC is acting as lead book-running manager of the offering and representative of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement dated the date of this prospectus, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the respective number of Class A Common Units set forth opposite each underwriter’s name below.
Underwriters | Number of Class A Common Units | |||
Janney Montgomery Scott LLC | ||||
Roth Capital Partners, LLC | ||||
TCBI Securities, Inc. | ||||
Seaport Global Securities LLC | ||||
|
| |||
Total | ||||
|
| |||
Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of the Class A Common Units (other than those covered by the underwriters’ option to purchase additional Class A Common Units described below) sold under the underwriting agreement. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the non-defaulting underwriters may be increased or the underwriting agreement may be terminated.
We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.
The underwriters are offering our Class A Common Units, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the Class A Common Units, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officers’ certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.
We have granted an option to the underwriters to purchase up to additional Class A Common Units at the public offering price, less the underwriting discount. The underwriters may exercise this option at any time or from time to time for 30 days from the date of this prospectus solely to cover any over-allotments. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional Class A Common Units proportionate to that underwriter’s initial amount as reflected in the above table. Any Class A Common Units issued or sold under the option will be issued and sold on the same terms and conditions as the other Class A Common Units that are the subject of this offering.
Underwriting Discounts and Expenses
The underwriters propose to offer our Class A Common Units to the public at the initial public offering price set forth on the cover page of this prospectus and to securities dealers at that price less a concession not in excess of $ per Class A Common Unit. After this offering, the public offering price, concession or any other term of this offering may be changed.
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The following table shows the public offering price, underwriting discount and proceeds before expenses to us. Such amounts are shown assuming both no exercise and full exercise by the underwriters of their option to purchase additional Class A Common Units.
| Total | ||||||||||||
| Per Class A Common Unit | Without Option | With Option | ||||||||||
Public offering price | $ | $ | $ | |||||||||
Underwriting discount | $ | $ | $ | |||||||||
|
|
|
|
|
| |||||||
Proceeds, before expenses, to us | $ | $ | $ | |||||||||
The estimated expenses of this offering payable by us, exclusive of the underwriting discount, are approximately $ , which includes the Company’s legal, accounting and printing costs and various other fees associated with registration of the offering of our Class A Common Units. The underwriting discount includes a structuring fee we will pay to Janney Montgomery Scott LLC equal to % of the gross proceeds of this offering (including upon exercise of the underwriters’ option to purchase additional Class A Common Units) for the evaluation, analysis and structuring of the partnership. We will reimburse the underwriters for certain reasonable out-of-pocket expenses (including those related to background checks, blue-sky laws and the review by the Financial Industry Regulatory Authority (“FINRA”) of the terms of sale of the Class A Common Units offered hereby) not to exceed $ in the aggregate.
No Sales of Similar Securities
We, the Sponsors, our directors and executive officers and the beneficial owners of more than 5% of our Class A Common Units and Class B Common Units have agreed with the underwriters not to offer, sell, contract to sell, pledge, transfer or otherwise dispose of, directly or indirectly, any of our Class A Common Units or any securities convertible into, exchangeable for, exercisable for, or repayable with our Class A Common Units for a period of 180 days after the date of this prospectus without first obtaining the written consent of the representative. Specifically, we and these other persons have agreed, with certain limited exceptions (including, without limitation, our ability to issue and sell additional our Class A Common Units to cover the underwriters’ over-allotment option (if applicable)), not to directly or indirectly:
| • | offer, pledge, sell or contract to sell any of our Class A Common Units; |
| • | sell any option or contract to purchase any of our Class A Common Units; |
| • | purchase any option or contract to sell any of our Class A Common Units; |
| • | grant any option, right or warrant for the sale of any of our Class A Common Units; |
| • | lend or otherwise dispose of or transfer any of our Class A Common Units; |
| • | file or cause to be filed any registration statement related to any of our Class A Common Units; or |
| • | enter into any swap hedging, collar or other agreement that can be reasonably expected to transfer, in whole or in part, the economic consequence of ownership of any of our Class A Common Units whether any such swap hedging, collar or other agreement is to be settled by delivery of any of our Class A Common Units or other securities, in cash or otherwise. |
This lock-up provision applies to all of our Class A Common Units and to securities convertible into or exchangeable or exercisable for or repayable with our Class A Common Units, including the Class B Common Units. It also applies to our Class A Common Units owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition.
Janney Montgomery Scott LLC may release any of our Class A Common Units and other securities subject to the lock-up agreements described above in whole or in part subject to the below considerations. When determining
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whether or not to release any of our Class A Common Units and other securities from lock-up agreements, Janney Montgomery Scott LLC will consider, among other factors, the unitholders’ reasons for requesting the release, the number of our Class A Common Units or other securities for which the release is being requested and market conditions at the time. However, Janney Montgomery Scott LLC has informed us that, as of the date of this prospectus, there are no agreements between it and any party that would allow such party to transfer any of our Class A Common Units or other securities, nor does it have any intention at this time of releasing any of our Class A Common Units or other securities subject to the lock-up agreements, prior to the expiration of the lock-up period.
We intend to apply to list the Class A Common Units on the NYSE American under the symbol “PRB.” We will not consummate this offering unless our Class A Common Units are approved for listing on the NYSE American. In order to meet the requirements for listing on that exchange, the underwriters will undertake to sell a minimum number of our Class A Common Units to a minimum number of beneficial owners as required by such exchange.
No Public Market; Determination of Offering Price
Prior to this offering, there has been no public market for our securities. The initial public offering price of the Class A Common Units will be determined through negotiations between us and the representative of the underwriters. In addition to prevailing market conditions, we expect to consider a number of factors in determining the initial public offering price including:
| • | the information set forth in this prospectus and otherwise available to the underwriters; |
| • | the market valuations of other publicly traded companies that we and the representative believe to be comparable to us; |
| • | our financial information; |
| • | the history of, and the prospects for, our company and the industry in which we compete; |
| • | an assessment of our management; |
| • | an assessment of the Sponsors, their past and present operations, and the prospects for, and timing of, our future revenues; |
| • | the present state of our development; |
| • | the above factors in relation to market values and various valuation measures of other companies engaged in activities similar to ours; and |
| • | other factors deemed relevant by the underwriters and us. |
An active trading market for our Class A Common Units may not develop or, if developed, be maintained or be liquid. It is also possible that after this offering our Class A Common Units will not trade in the public market at or above the public offering price.
The underwriters do not expect to sell more than % of the Class A Common Units in the aggregate to accounts over which they exercise discretionary authority.
Price Stabilization, Short Positions and Penalty Bids
Until the distribution of our Class A Common Units is completed, SEC rules may limit underwriters and selling group members from bidding for and purchasing our Class A Common Units. However, the underwriters may engage in transactions that stabilize the price of the Class A Common Units, such as bids or purchases to peg, fix or maintain that price.
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In connection with this offering, the underwriters may purchase and sell our Class A Common Units in the open market. These transactions may include short sales, purchases on the open market to cover positions created by short sales and stabilizing transactions. Short sales involve the sale by the underwriters of a greater number of our Class A Common Units than they are required to purchase in this offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ securities underlying their over-allotment option, as described above. The underwriters may close out any covered short position by either exercising their option or purchasing our Class A Common Units in the open market. In determining the source of our Class A Common Units to close out the covered short position, the underwriters will consider, among other things, the price of our Class A Common Units available for purchase in the open market as compared to the price at which they may purchase our Class A Common Units through the option. “Naked” short sales are sales in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing our Class A Common Units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our Class A Common Units in the open market after pricing that could adversely affect investors who purchase in this offering. Stabilizing transactions consist of various bids for, or purchases of, our Class A Common Units made by the underwriters in the open market prior to the completion of this offering.
The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the underwriters have repurchased our Class A Common Units sold by or for the account of such underwriter in stabilizing or short covering transactions.
Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of our Class A Common Units or preventing or retarding a decline in the market price of our Class A Common Units. As a result, the price of our Class A Common Units may be higher than the price that might otherwise exist in the open market.
Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our Class A Common Units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.
In connection with this offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means and in electronic format, such as by e-mail. In addition, the underwriters may facilitate Internet distribution for this offering to certain of their Internet subscription customers. The underwriters may allocate a limited number of our Class A Common Units for sale to their online brokerage customers. An electronic prospectus may be available on the websites maintained by the underwriters. Other than the prospectus in electronic format, the information on any underwriter’s website and any information contained in any other website maintained by an underwriter is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter in its capacity as underwriter, and should not be relied upon by investors.
The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage, and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to us and to persons and entities with relationships with us, for which they received or will receive customary fees and expenses.
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In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors, and employees may purchase, sell or hold a broad array of investments and actively traded securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of ours (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships with us. The underwriters and their respective affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.
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VALIDITY OF THE CLASS A COMMON UNITS
The validity of the Class A Common Units and certain tax matters will be passed upon for us by Akin Gump Strauss Hauer & Feld LLP, Dallas, Texas. Certain legal matters in connection with the Class A Common Units offered by us will be passed upon for the underwriters by Jones Walker LLP, New Orleans, Louisiana.
The consolidated financial statements of Peak Exploration & Production, LLC as of December 31, 2023 and 2022 and for the years then ended included in this prospectus has been audited by Moss Adams LLP, an independent registered public accounting firm, as stated in their report, which is included herein. Such financial statements are included in reliance upon the report of such firm given their authority as experts in accounting and auditing.
The consolidated financial statements of Peak BLM Lease LLC and Subsidiary as of December 31, 2023 and 2022 and for the years then ended included in this prospectus has been audited by Moss Adams LLP, an independent registered public accounting firm, as stated in their report, which is included herein. Such financial statements are included in reliance upon the report of such firm given their authority as experts in accounting and auditing
Estimates of our reserves, related future net cash flows and the present values thereof related to our properties as of December 31, 2023 and December 31, 2022 included elsewhere in this prospectus were based upon reserve reports prepared by Cawley Gillespie, our independent petroleum engineers. We have included these estimates in reliance on the authority of such firms as experts in such matters.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the Class A Common Units offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the Class A Common Units offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.
As a result of the offering, we will become subject to full information requirements of the Exchange Act. We intend to furnish or make available to our unitholders annual reports on Form 10-K containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each of our fiscal years. Additionally, we intend to file other periodic reports with the SEC on Form 8-K, as required by the Exchange Act.
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information discussed in this prospectus and the documents and other information incorporated by reference herein includes “forward-looking statements.” All statements, other than statements of historical facts, included or incorporated by reference herein concerning, among other things, future distributions, returns, performance, capital expenditures, increases and levels of oil and natural gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans, goals and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil and natural gas. We disclose important factors that could cause our actual results to differ materially from our expectations as discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:
| • | federal and state regulations and laws; |
| • | capital requirements and uncertainty of obtaining additional funding on terms acceptable to us; |
| • | risks and restrictions related to our debt agreements and the level of our indebtedness; |
| • | our ability to use derivative instruments to manage commodity price risk; |
| • | realized oil and natural gas prices; |
| • | a decline in oil and natural gas production, and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital; |
| • | constraints in the Powder River Basin with respect to gathering, transportation and processing facilities and marketing; |
| • | unsuccessful drilling and completion activities and the possibility of resulting write-downs; |
| • | geographical concentration of our operations; |
| • | our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in commercially viable quantities; |
| • | shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel; |
| • | adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities; |
| • | incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of such acquired properties; |
| • | hazardous drilling operations, including those associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions; |
| • | limited control over non-operated properties; |
| • | title defects to our properties and inability to retain our leases; |
| • | our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage; |
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| • | our ability to retain key members of our senior management and key technical employees; |
| • | risks relating to managing our growth, particularly in connection with the integration of significant acquisitions; |
| • | impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation; |
| • | changes in tax laws; |
| • | effects of competition; and |
| • | seasonal weather conditions. |
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this prospectus. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as required by law, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.
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| Page | ||||
PRO FORMA FINANCIAL STATEMENTS | ||||
Peak Resources LP | ||||
| F-2 | ||||
Introduction | ||||
| F-4 | ||||
Notes to Unaudited Pro Forma Condensed Combined Financial Statements | F-7 | |||
HISTORICAL FINANCIAL STATEMENTS | ||||
Peak Exploration & Production, LLC | ||||
Annual Financial Statements (Audited) | ||||
| F-12 | ||||
Audited Consolidated Financial Statements as of and for the years ended December 31, 2023 and 2022 | F-13 | |||
| F-17 | ||||
| F-32 | ||||
Interim Financial Statements (Unaudited) | ||||
| F-36 | ||||
| F-40 | ||||
Peak BLM Lease LLC | ||||
Annual Financial Statements (Audited) | ||||
| F-51 | ||||
Audited Financial Statements as of and for the years ended December 31, 2023 and 2022 | F-52 | |||
| F-56 | ||||
| F-62 | ||||
Interim Financial Statements (Unaudited) | ||||
| F-66 | ||||
| F-70 | ||||
F-1
Peak Resources LP
Pro Forma Condensed Combined Financial Statements
(Unaudited)
(in thousands)
Peak Resources LP (the “Company”) is an independent limited partnership that was recently formed to hold investments in oil and natural gas businesses and assets owned by certain investments partnerships managed by Yorktown Partners LLC (“Yorktown”), management and other investors who are not affiliated with Yorktown or management. The unaudited pro forma condensed combined financial statements have been prepared in accordance with Article 11 of Regulation S-X under the Securities Act, using assumptions set forth in the notes to the unaudited pro forma condensed combined financial statements. The following unaudited pro forma condensed combined financial statements of the Company reflect the historical results of Peak E&P and PBLM on a pro forma combined basis, as adjusted to give effect to the following transactions:
| • | The Reorganization Transactions as described in “Prospectus Summary — Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction — Reorganization Transactions and Partnership Structure” elsewhere in this prospectus; and |
| • | The issuance and sale by us to the public of Class A Common Units in this offering and the receipt of net proceeds as described in “Use of Proceeds.” |
We expect that $ of the net proceeds will remain at the Company initially designated as a reserve for general partnership purposes, including in order to pay distributions on our Class A Common Units, if needed. The remaining $ net proceeds will be contributed to the Company’s subsidiaries for capital expenditures and working capital purposes. For purposes of the unaudited pro forma financial statements, the Offering is defined as the planned issuance and sale to the public of Class A Common Units of the Company at an assumed initial public offering price of $ per Class A Common Unit as contemplated by this prospectus. The gross proceeds from the sale of the Class A Common Units are expected to be $ million, reduced by underwriting discounts of $ , estimated expenses of $ and the structuring fee of $ .
The unaudited pro forma condensed combined balance sheet as of June 30, 2024 gives effect to the described transactions as if they had been completed on June 30, 2024. The unaudited pro forma condensed combined statements of operations for six months ended June 30, 2024 and the year ended December 31, 2023 gives effect to described transactions as if they had been completed on January 1, 2023.
The entities to be contributed in connection with the initial public offering and the Reorganization Transactions described in this prospectus have a high degree of common ownership and therefore the Reorganization Transactions are accounted for as common control transactions. Peak E&P and PBLM have been in operation and under common control for the entirety of the periods presented. Affiliates of Yorktown will control the general partner, which will ultimately control business operations. Accordingly, the financial statements are presented in accordance with SEC requirements for predecessor financial statements to be included in the registration statement.
The pro forma data presented reflect events directly attributable to the described transactions, based upon currently available information and certain assumptions the Company believes are reasonable. The pro forma data is not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses associated with being a public company.
The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as
F-2
contemplated and the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed combined financial statements. The Company has not included any adjustments depicting synergies or dis-synergies of the Reorganization Transactions, and the Company has not given pro forma effect to the incremental general and administrative expenses that the Company expects to incur annually as a result of being a publicly-traded partnership.
The unaudited pro forma condensed combined financial statements and related notes are presented for illustrative purposes only. If the Reorganization Transactions and the Offering had occurred in the past, the Company’s operating results might have been materially different from those presented in the unaudited pro forma condensed combined financial statements. The unaudited pro forma condensed combined financial statements should not be relied upon as an indication of the financial position that would have existed or the operating results the Company would have achieved if the Reorganization Transactions and the Offering had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma condensed combined financial statements and should not be relied upon as an indication of the future results the Company will have after the contemplation of the Reorganization Transactions and the Offering. The unaudited pro forma combined financial statements should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as the historical consolidated financial statements of Peak E&P and PBLM and related notes and other financial information included elsewhere in this prospectus.
F-3
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
AS OF JUNE 30, 2024
(in thousands)
| Historical (Predecessor) | ||||||||||||||||||||||||||||||||
| Peak E&P | PBLM | Combined Predecessor | Reorganization Transactions | Offering Transaction | Pro Forma | |||||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||||||||||
Current assets: | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 8,099 | $ | 1,071 | $ | 9,170 | $ | — | $ | (a | ) | $ | 9,170 | |||||||||||||||||||
Accounts receivable, net | 10,995 | 448 | 11,443 | — | — | 11,443 | ||||||||||||||||||||||||||
Prepaid expenses and other current assets | 643 | 190 | 833 | — | — | 833 | ||||||||||||||||||||||||||
Commodity derivatives | 550 | — | 550 | — | — | 550 | ||||||||||||||||||||||||||
Inventories | 98 | — | 98 | — | — | 98 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Total current assets | 20,385 | 1,709 | 22,094 | — | — | 22,094 | ||||||||||||||||||||||||||
Oil and natural gas property and equipment, based on successful efforts method of accounting, net | 134,726 | 52,671 | 187,397 | — | — | 187,397 | ||||||||||||||||||||||||||
Other property, plant and equipment, net | 1,782 | — | 1,782 | — | — | 1,782 | ||||||||||||||||||||||||||
Right-of-use assets | 405 | — | 405 | — | — | 405 | ||||||||||||||||||||||||||
Investments | — | — | — | 36,397 | (b) | — | 36,397 | |||||||||||||||||||||||||
Other assets, net | 1,776 | — | 1,776 | — | — | 1,776 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Total assets | $ | 159,074 | $ | 54,380 | $ | 213,454 | $ | 36,397 | $ | — | $ | 249,851 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
LIABILITIES AND MEMBER’S EQUITY |
| |||||||||||||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||||||||||||||
Accounts payable and accrued expenses | $ | 4,668 | $ | 180 | $ | 4,848 | $ | — | $ | — | $ | 4,848 | ||||||||||||||||||||
Production and ad valorem taxes payable | 2,853 | — | 2,853 | — | — | 2,853 | ||||||||||||||||||||||||||
Oil and natural gas revenue payable | 10,173 | — | 10,173 | — | — | 10,173 | ||||||||||||||||||||||||||
Commodity derivatives | 3,560 | — | 3,560 | — | — | 3,560 | ||||||||||||||||||||||||||
Deferred tax liabilities | — | — | — | 10,314 | (e | ) | — | 10,314 | ||||||||||||||||||||||||
Right-of-use liabilities | 147 | — | 147 | — | — | 147 | ||||||||||||||||||||||||||
Current portion of long-term debt | 6,200 | — | 6,200 | — | — | 6,200 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Total current liabilities | 27,601 | 180 | 27,781 | 10,314 | — | 38,095 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Long-term debt, net | 48,610 | — | 48,610 | — | — | 48,610 | ||||||||||||||||||||||||||
Other noncurrent liabilities: | ||||||||||||||||||||||||||||||||
Asset retirement obligation | 2,863 | 52 | 2,915 | — | — | 2,915 | ||||||||||||||||||||||||||
Ad valorem taxes | 9,196 | — | 9,196 | — | — | 9,196 | ||||||||||||||||||||||||||
Commodity derivatives | 4,241 | — | 4,241 | — | — | 4,241 | ||||||||||||||||||||||||||
Right-of-use liabilities | 280 | — | 280 | — | — | 280 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Total other noncurrent liabilities | 16,580 | 52 | 16,632 | — | — | 16,632 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Total liabilities | 92,791 | 232 | 93,023 | 10,314 | — | 103,337 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Commitments and contingencies | ||||||||||||||||||||||||||||||||
Member’s equity: | ||||||||||||||||||||||||||||||||
Preferred equity | 95,886 | — | 95,886 | (95,886 | ) | (c | ) | — | — | |||||||||||||||||||||||
Common equity | 242,518 | 57,000 | 299,518 | 132,283 | (b | ) | (a | ) | 421,487 | |||||||||||||||||||||||
| (10,314 | ) | (e | ) | |||||||||||||||||||||||||||||
Accumulated deficit | (272,121 | ) | (2,852 | ) | (274,973 | ) | — | — | (274,973 | ) | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Total member’s equity | 66,283 | 54,148 | 120,431 | 26,083 | — | 146,514 | ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Total liabilities and member’s equity | $ | 159,074 | $ | 54,380 | $ | 213,454 | $ | 36,397 | $ | — | $ | 249,851 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
F-4
PEAK RESOURCES LP
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2024
(in thousands)
| Historical (Predecessor) | ||||||||||||||||||||||||||||
| Peak E&P | PBLM | Combined Predecessor | Reorganization Transactions | Offering Transaction | Pro Forma | |||||||||||||||||||||||
REVENUES: | ||||||||||||||||||||||||||||
Oil and natural gas sales, net | $ | 22,977 | $ | 1,552 | $ | 24,529 | $ | — | $ | — | $ | 24,529 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total revenues, net | 22,977 | 1,552 | 24,529 | — | — | |||||||||||||||||||||||
OPERATING EXPENSES: | ||||||||||||||||||||||||||||
Lease operating | 6,050 | 347 | 6,397 | — | — | 6,397 | ||||||||||||||||||||||
Production and ad valorem taxes | 3,057 | 209 | 3,266 | — | — | 3,266 | ||||||||||||||||||||||
Depletion, depreciation and amortization | 6,555 | 608 | 7,163 | — | — | 7,163 | ||||||||||||||||||||||
Accretion | 114 | 2 | 116 | — | — | 116 | ||||||||||||||||||||||
Abandonment | 1,921 | 52 | 1,973 | — | — | 1,973 | ||||||||||||||||||||||
Impairment of oil and natural gas properties | — | — | — | — | — | — | ||||||||||||||||||||||
General and administrative | 3,606 | 880 | 4,486 | — | — | 4,486 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total operating expenses | 21,303 | 2,098 | 23,401 | — | — | 23,401 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Income (loss) from operations | 1,674 | (546 | ) | 1,128 | — | — | 1,128 | |||||||||||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||||||||||
Gain on commodity derivatives | (6,992 | ) | — | (6,992 | ) | — | — | (6,992 | ) | |||||||||||||||||||
Interest expense, net | (4,330 | ) | — | (4,330 | ) | — | — | (4,330 | ) | |||||||||||||||||||
Loss from retirement of long-term debt | — | — | — | — | — | — | ||||||||||||||||||||||
Investment income | — | — | 2,304 | (d | ) | — | 2,304 | |||||||||||||||||||||
Gain on sale of assets | (23 | ) | — | (23 | ) | — | — | (23 | ) | |||||||||||||||||||
Other gain | 52 | 38 | 90 | — | — | 90 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total other income (expense) | (11,293 | ) | 38 | (11,255 | ) | — | (8,951 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net income (loss) before income taxes | (9,619 | ) | (508 | ) | (10,127 | ) | 2,304 | — | (7,823 | ) | ||||||||||||||||||
Income tax benefit (provision) | — | — | — | 1,641 | (e | ) | — | 1,641 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
NET INCOME (LOSS) | $ | (9,619 | ) | $ | (508 | ) | $ | (10,127 | ) | $ | 3,945 | $ | — | $ | (6,182 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net income (loss) per Common Unit | ||||||||||||||||||||||||||||
Basic | $ | |||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||
Diluted | $ | |||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||
Weighted Average Common Units Outstanding | ||||||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||
F-5
PEAK RESOURCES LP
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2023
(in thousands)
| Historical (Predecessor) | ||||||||||||||||||||||||||||
| Peak E&P | PBLM | Combined Predecessor | Reorganization Transactions | Offering Transaction | Pro Forma | |||||||||||||||||||||||
REVENUES: | ||||||||||||||||||||||||||||
Oil and natural gas sales, net | $ | 49,631 | $ | 4,502 | $ | 54,133 | $ | — | $ | — | $ | 54,133 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total revenues, net | 49,631 | 4,502 | 54,133 | — | — | 54,133 | ||||||||||||||||||||||
OPERATING EXPENSES: | ||||||||||||||||||||||||||||
Lease operating | 13,243 | 706 | 13,949 | — | — | 13,949 | ||||||||||||||||||||||
Production and ad valorem taxes | 6,943 | 565 | 7,508 | — | — | 7,508 | ||||||||||||||||||||||
Depletion, depreciation and amortization | 27,061 | 1,740 | 28,801 | — | — | 28,801 | ||||||||||||||||||||||
Accretion | 223 | 4 | 227 | — | — | 227 | ||||||||||||||||||||||
Abandonment | 2,882 | 50 | 2,932 | — | — | 2,932 | ||||||||||||||||||||||
Impairment of oil and natural gas properties | 111,871 | — | 111,871 | — | — | 111,871 | ||||||||||||||||||||||
General and administrative | 6,566 | 1,264 | 7,830 | — | — | 7,830 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total operating expenses | 168,789 | 4,329 | 173,118 | — | — | 173,118 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Income (loss) from operations | (119,158 | ) | 173 | (118,985 | ) | — | — | (118,985 | ) | |||||||||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||||||||||
Gain on commodity derivatives | 1,604 | — | 1,604 | — | — | 1,604 | ||||||||||||||||||||||
Interest expense, net | (8,867 | ) | — | (8,867 | ) | — | — | (8,867 | ) | |||||||||||||||||||
Loss from retirement of long-term debt | (1,080 | ) | — | (1,080 | ) | — | — | (1,080 | ) | |||||||||||||||||||
Investment income | — | — | — | 9,675 | (d | ) | — | 9,675 | ||||||||||||||||||||
Gain on sale of assets | 1,240 | — | 1,240 | — | — | 1,240 | ||||||||||||||||||||||
Other gain | 1,619 | 33 | 1,652 | — | — | 1,652 | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total other income (expense) | (5,484 | ) | 33 | (5,451 | ) | 9,675 | — | 4,224 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net income (loss) before income taxes | (124,642 | ) | 206 | (124,436 | ) | 9,675 | — | (114,761 | ) | |||||||||||||||||||
Income tax benefit (provision) | — | — | — | 24,138 | (e | ) | — | 24,138 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
NET INCOME (LOSS) | $ | (124,642 | ) | $ | 206 | $ | (124,436 | ) | $ | 33,813 | $ | — | $ | (90,623 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net income (loss) per Class A Common Unit | ||||||||||||||||||||||||||||
Basic | $ | |||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||
Diluted | $ | |||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||
Weighted Average Class A Common Units Outstanding | ||||||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||
F-6
Peak Resources LP
Notes to Unaudited Pro Forma Condensed Combined Financial Statements
| 1. | BASISOF PRESENTATION, CORPORATE REORGANIZATIONANDTHE OFFERING |
The historical financial information is derived from the financial statements of Peak E&P and PBLM included elsewhere in this prospectus. The unaudited pro forma condensed combined balance sheet as of June 30, 2024 was prepared as if the transactions had occurred on June 30, 2024. The unaudited pro forma condensed combined statement of operations for six months ended June 30, 2024 and the year ended December 31, 2023 was prepared assuming the transactions occurred on January 1, 2023.
Upon closing the Offering, the Company expects to incur direct, incremental non-recurring general and administrative expenses as a result of being publicly traded, including the costs of the Offering and the costs associated with the initial implementation of the Company’s internal controls and testing. The Company also expects to incur additional direct, incremental recurring costs related to being a public company including, but not limited to, costs associated the employment of additional personnel, compliance under the Exchange Act and applicable securities exchange requirements, annual and quarterly reports to be filed with the SEC, tax return preparation, independent auditor fees, incremental legal fees, investor relations activities, registrar and transfer agent fees, and incremental director and officer liability insurance costs. These direct, incremental general and administrative expenditures are not reflected in the historical financial statements or in the unaudited pro forma condensed combined financial statements.
Prior to the closing of the Offering, the following transactions, which we refer to as the Reorganization Transactions, will occur:
| • | 100% of the common units in Peak E&P, including the common units held by Yorktown Energy Partners IX, L.P. (“Yorktown IX”) and the members of our management team, will be contributed to the Company in exchange for Class B Common Units; |
| • | 100% of the preferred units in Peak E&P, including the preferred units held by Yorktown Energy Partners X, L.P. (“Yorktown X”), and Yorktown Energy Partners XI, L.P. (“Yorktown XI”), will be contributed to the Company in exchange for Class B Common Units; |
| • | 100% of the ownership interests in PBLM, all of which is held by Yorktown XI, will be contributed to the Company in exchange for Class B Common Units; and |
| • | an aggregate of approximately 16% of the equity in PetroSantander, Inc. (“PSI”), held by Yorktown Energy Partners VIII, L.P. (“Yorktown VIII”) and Yorktown IX, will be contributed to the Company in exchange for Class A Common Units and Class B Common Units, respectively. |
Yorktown VIII, Yorktown IX, Yorktown X, and Yorktown XI, which are investment partnerships managed by Yorktown Partners LLC (“Yorktown”), will beneficially own approximately % of our outstanding Class A Common Units immediately after this offering (or % of our outstanding Class A Common Units on an as-converted basis as a result of their ownership of Class B Common Units). Immediately upon the consummation of the Reorganization Transactions, the funds affiliated with Yorktown will own approximately % of the outstanding Class B Common Units.
The unaudited pro forma condensed combined financial information is provided for illustrative purposes only and does not purport to represent what the actual consolidated results of operations or the consolidated financial position would have been had the transactions occurred on the dates noted above, nor are they indicative of future consolidated results of operations or consolidated financial position. In the Company’s opinion, all adjustments that are necessary to present fairly the unaudited pro forma condensed combined financial information have been made.
F-7
| 2. | PRO FORMA ADJUSTMENTSAND ASSUMPTIONS |
The following adjustments were made in the preparation of the unaudited pro forma condensed combined financial statements:
| (a) | Adjustment reflects estimated gross proceeds of $ million from the issuance and sale of Class A Common Units reduced by underwriting discounts, commissions and estimated expenses related to the Offering of $ million, in the aggregate. We expect that $ of the net proceeds will remain at the Company initially designated as a reserve for general partnership purposes, including in order to pay distributions on Class A Common Units if needed. The remaining $ net proceeds will be contributed to the Company’s subsidiaries for capital expenditures and working capital purposes. Additionally, to the extent we are able to enter into the New Credit Agreement after the closing of the Offering, a portion of the net proceeds of this offering will be used to repay in full and terminate our Existing Credit Agreement. |
| (b) | Adjustment reflects the cost basis of the contribution of aggregate of approximately 16% of the equity in PSI, held by Yorktown VIII and Yorktown IX, which will be contributed to the Company in exchange for Class A Common Units and Class B Common Units, respectively. |
| (c) | Adjustment to reflect the contribution of 100% of the preferred units in Peak E&P, including the preferred units held by Yorktown X and Yorktown XI, in exchange for Class B Common Units. For purposes of these unaudited pro forma condensed combined financial statements, the contribution of preferred units in Peak E&P and subsequent issuance of Class B Common Units is assumed to be a modification, with no incremental value to be recognized. |
| (d) | Adjustment to reflect distributions received from PSI representing a return on investment during the six months ended June 30, 2024 and the year ended December 31, 2023. |
| (e) | Pro forma net loss reflects a pro forma income tax benefit of $1.6 million for the six months ended June 30, 2024 and $24.1 million for the year ended December 31, 2023, respectively, all of which is associated with the income tax effects of the corporate reorganization described unde “Prospectus Summary—Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction” and this offering. Our predecessor was not subject to U.S. federal income tax at an entity level. As a result, the consolidated net loss in our historical financial statements does not reflect the tax expense or benefit we would have incurred if we were subject to U.S. federal income tax at an entity level during such periods. |
| 3. | SUPPLEMENTAL UNAUDITED PRO FORMA COMBINED OILAND NATURAL GAS RESERVESAND STANDARDIZED MEASURE INFORMATION |
The following tables present the estimated pro forma standardized measure of the discounted future net cash flows and changes applicable to Peak Resources LP’s proved reserves. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions. The unaudited pro forma combined proved reserve information is not necessarily indicative of the results that might have occurred had the transactions taken place nor is it intended to be a projection of future results.
The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions or removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, proved reserve estimates may differ significantly from the quantities of oil and natural gas ultimately recovered. For both Peak E&P and PBLM, the reserve estimates shown below were determined using the average first day of the month price for each of the preceding 12 months for oil and natural gas for the year ended December 31, 2023.
F-8
Estimated Oil and Natural Gas Reserves
| As of December 31, 2023 | Pro Forma Adjustments (3) | Pro Forma Combined | ||||||||||||||
| Peak E&P | PBLM | |||||||||||||||
Estimated Proved Developed Reserves: | ||||||||||||||||
Oil (MBbl) | 4,305.6 | 273.9 | — | 4,579.5 | ||||||||||||
Natural Gas (MMcf)(1) | 20,374.3 | 952.6 | — | 21,326.9 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total (Mboe)(1) | 7,701.3 | 432.7 | — | 8,134.0 | ||||||||||||
Estimated Proved Undeveloped Reserves: | ||||||||||||||||
Oil (MBbl) | 705.2 | — | 4,231.0 | 4,936.2 | ||||||||||||
Natural Gas (MMcf)(1) | 7,860.5 | — | 11,204.5 | 19,065.0 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total (Mboe)(1) | 2,015.3 | — | 6,098.4 | 8,113.7 | ||||||||||||
Estimated Proved Reserves: | ||||||||||||||||
Oil (MBbl) | 5,010.8 | 273.9 | 4,231.0 | 9,515.7 | ||||||||||||
Natural Gas (MMcf)(1) | 28,234.8 | 952.6 | 11,204.5 | 40,391.9 | ||||||||||||
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|
|
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|
| |||||||||
Total (Mboe)(2) | 9,716.6 | 432.7 | 6,098.4 | 16,247.7 | ||||||||||||
| (1) | The Company’s reserves are reported in two streams: oil and natural gas. The economic value of the NGLs is included in our natural gas price and reserves. |
| (2) | Assumes a ratio of 6 Mcf of natural gas per Boe. |
| (3) | The development plan associated with the 2023 proved undeveloped reserves includes the use of a portion of the estimated net proceeds from the offering, together with cash flow from operations. Approximately 6,100 Mboe of proved undeveloped reserves will be developed using a portion of the estimated proceeds from the offering. |
A summary of the Company’s change in quantities of proved oil and natural gas reserves for the year ended December 31, 2023 are as follows:
| Oil (MBbls) | ||||||||||||||||
| Peak E&P | PBLM | Pro Forma Adjustments | Total | |||||||||||||
Proved reserves as of December 31, 2022 | 6,930 | 481 | — | 7,411 | ||||||||||||
Revisions of previous estimates | (1,589 | ) | (177 | ) | — | (1,767 | ) | |||||||||
Extensions, discoveries and other additions | 250 | 22 | 4,231 | 4,503 | ||||||||||||
Production | (572 | ) | (53 | ) | — | (625 | ) | |||||||||
Purchases (sales) of minerals in place | (8 | ) | — | — | (8 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Proved reserves as of December 31, 2023 | 5,011 | 274 | 4,231 | 9,515 | ||||||||||||
|
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|
|
|
|
| |||||||||
Proved developed reserves | ||||||||||||||||
Beginning of year | 5,359 | 341 | — | 5,700 | ||||||||||||
End of year | 4,306 | 273 | — | 4,579 | ||||||||||||
Proved undeveloped reserves | ||||||||||||||||
Beginning of year | 1,571 | 140 | — | 1,711 | ||||||||||||
End of year | 705 | — | 4,231 | 4,936 | ||||||||||||
| Natural Gas (MMcf) | ||||||||||||||||
| Peak E&P | PBLM | Pro Forma Adjustments | Total | |||||||||||||
Proved reserves as of December 31, 2022 | 35,244 | 1,303 | — | 36,547 | ||||||||||||
Revisions of previous estimates | (6,048 | ) | (634 | ) | — | (6,682 | ) | |||||||||
Extensions, discoveries and other additions | 1,614 | 505 | 11,205 | 13,324 | ||||||||||||
Production | (2,484 | ) | (221 | ) | — | (2,705 | ) | |||||||||
Purchases (sales) of minerals in place | (92 | ) | — | — | (92 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Proved reserves as of December 31, 2023 | 28,235 | 953 | 11,205 | 40,392 | ||||||||||||
|
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|
|
|
|
| |||||||||
F-9
| Natural Gas (MMcf) | ||||||||||||||||
| Peak E&P | PBLM | Pro Forma Adjustments | Total | |||||||||||||
Proved developed reserves | ||||||||||||||||
Beginning of year | 23,079 | 795 | — | 23,874 | ||||||||||||
End of year | 20,374 | 953 | — | 21,327 | ||||||||||||
Proved undeveloped reserves | ||||||||||||||||
Beginning of year | 12,165 | 508 | — | 12,673 | ||||||||||||
End of year | 7,860 | — | 11,205 | 19,065 | ||||||||||||
| Total (Mboe) | ||||||||||||||||
| Peak E&P | PBLM | Pro Forma Adjustments | Total | |||||||||||||
Proved reserves as of December 31, 2022 | 12,804 | 699 | — | 13,503 | ||||||||||||
Revisions of previous estimates | (2,597 | ) | (282 | ) | — | (2,879 | ) | |||||||||
Extensions, discoveries and other additions | 519 | 107 | 6,098 | 6,724 | ||||||||||||
Production | (986 | ) | (90 | ) | — | (1,076 | ) | |||||||||
Purchases (sales) of minerals in place | (24 | ) | — | — | (24 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Proved reserves as of December 31, 2023 | 9,717 | 433 | 6,098 | 16,248 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Proved developed reserves | ||||||||||||||||
Beginning of year | 9,205 | 474 | — | 9,679 | ||||||||||||
End of year | 7,701 | 433 | — | 8,134 | ||||||||||||
Proved undeveloped reserves | ||||||||||||||||
Beginning of year | 3,599 | 225 | — | 3,824 | ||||||||||||
End of year | 2,016 | — | 6,098 | 8,114 | ||||||||||||
The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2023 (in thousands):
Standardized Measure of Discounted Future Net Cash Flows
| As of December 31, 2023 | Pro Forma Adjustments (1) | Pro Forma Combined | ||||||||||||||
| Peak E&P | PBLM | |||||||||||||||
Future cash inflows | $ | 461,643 | $ | 23,553 | $ | 358,788 | $ | 843,984 | ||||||||
Future production costs | (229,284 | ) | (12,082 | ) | (120,320 | ) | (361,686 | ) | ||||||||
Future development and abandonment costs | (29,650 | ) | (90 | ) | (101,346 | ) | (131,086 | ) | ||||||||
Future income taxes | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Future net cash flows | 202,709 | 11,381 | 137,122 | 351,212 | ||||||||||||
10% annual discount factor | (87,145 | ) | (3,909 | ) | (73,672 | ) | (164,726 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Standardized measure of discounted future net cash flows | $ | 115,564 | $ | 7,472 | $ | 63,450 | $ | 186,486 | ||||||||
|
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|
|
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|
|
| |||||||||
| (1) | The development plan associated with the 2023 proved undeveloped reserves includes the use of a portion of the estimated net proceeds from the offering, together with cash flow from operations. Approximately 6,100 MBoe of proved undeveloped reserves are expected to be developed using a portion of the estimated proceeds from the offering, which increases the standardized measure by approximately $63.5 million. |
The change in the pro forma standardized measure of discounted estimated future net cash flows were as follows for the year ended December 31, 2023 (in thousands):
F-10
Changes in Standardized Measure of Discounted Future Net Cash Flows
| Year Ended December 31, 2023 | Pro Forma Adjustments (1) | Pro Forma Combined | ||||||||||||||
| Peak E&P | PBLM | |||||||||||||||
Standardized measure, beginning of year | $ | 259,136 | $ | 17,077 | $ | — | $ | 276,213 | ||||||||
Net change in prices and production costs | (90,493 | ) | (3,454 | ) | — | (93,947 | ) | |||||||||
Changes in estimated future development and abandonment costs | 589 | — | — | 589 | ||||||||||||
Sales of crude oil and natural gas produced, net of production costs | (29,465 | ) | (3,243 | ) | — | (32,708 | ) | |||||||||
Extensions, discoveries and improved recoveries, less related costs | 7,096 | 1,134 | 63,450 | 71,680 | ||||||||||||
Purchases (sales) of minerals in place, net | (195 | ) | — | — | (195 | ) | ||||||||||
Revisions of previous quantity estimates | (49,082 | ) | (5,754 | ) | — | (54,836 | ) | |||||||||
Development costs incurred during the period | — | 495 | — | 495 | ||||||||||||
Change in income taxes | — | — | — | — | ||||||||||||
Accretion of discount | 25,913 | 1,708 | — | 27,621 | ||||||||||||
Change in timing of estimated future production and other | (7,935 | ) | (491 | ) | — | (8,426 | ) | |||||||||
|
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|
|
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| |||||||||
Standardized measure, end of year | $ | 115,564 | $ | 7,472 | $ | 63,450 | $ | 186,486 | ||||||||
|
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|
|
|
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| |||||||||
| (1) | The development plan associated with the 2023 proved undeveloped reserves includes the use of a portion of the estimated net proceeds from the offering, together with cash flow from operations. Approximately 6,100 Mboe of proved undeveloped reserves are expected to be developed using a portion of the estimated proceeds from the offering, which increases the standardized measure by approximately $63.5 million. |
* * * * *
F-11
Report of Independent Registered Public Accounting Firm
To the Board Managers and Members of
Peak Exploration & Production, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Peak Exploration & Production, LLC (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, members’ equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2023 and 2022, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Moss Adams LLP
Denver, Colorado
April 29, 2024
We have served as the Company’s auditor since 2017.
F-12
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
(in thousands)
| December 31, | ||||||||
| 2023 | 2022 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 11,762 | $ | 1,940 | ||||
Accounts receivable, net | 17,236 | 14,260 | ||||||
Prepaid expenses and other current assets | 218 | 795 | ||||||
Commodity derivatives | 696 | — | ||||||
Inventories | 97 | 206 | ||||||
|
|
|
| |||||
Total current assets | 30,009 | 17,201 | ||||||
Oil and natural gas property and equipment, based on successful efforts method of accounting, net | 144,775 | 267,402 | ||||||
Other property, plant and equipment, net | 1,862 | 2,056 | ||||||
Right-of-use assets | 478 | 622 | ||||||
Other assets, net | 2,001 | 4,337 | ||||||
|
|
|
| |||||
Total assets | $ | 179,125 | $ | 291,618 | ||||
|
|
|
| |||||
LIABILITIES AND MEMBER’S EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued expenses | $ | 14,365 | $ | 5,969 | ||||
Production and ad valorem taxes payable | 3,322 | 3,160 | ||||||
Oil and natural gas revenue payable | 15,936 | 11,275 | ||||||
Commodity derivatives | — | 5,587 | ||||||
Right-of-use liabilities | 160 | 131 | ||||||
Current portion of long-term debt | 6,200 | — | ||||||
|
|
|
| |||||
Total current liabilities | 39,983 | 26,122 | ||||||
|
|
|
| |||||
Long-term debt, net | 49,765 | 52,000 | ||||||
Other noncurrent liabilities: | ||||||||
Asset retirement obligation | 2,749 | 2,491 | ||||||
Ad valorem taxes | 9,197 | 9,796 | ||||||
Commodity derivatives | 1,191 | 173 | ||||||
Right-of-use liabilities | 338 | 492 | ||||||
|
|
|
| |||||
Total other noncurrent liabilities | 13,475 | 12,952 | ||||||
|
|
|
| |||||
Total liabilities | 103,223 | 91,074 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Member’s equity: | ||||||||
Preferred equity | 95,886 | 95,886 | ||||||
Common equity | 242,518 | 242,518 | ||||||
Accumulated deficit | (262,502 | ) | (137,860 | ) | ||||
|
|
|
| |||||
Total member’s equity | 75,902 | 200,544 | ||||||
|
|
|
| |||||
Total liabilities and member’s equity | $ | 179,125 | $ | 291,618 | ||||
|
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|
| |||||
F-13
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
REVENUES: | ||||||||
Oil and natural gas sales, net | $ | 49,631 | $ | 84,601 | ||||
|
|
|
| |||||
Total revenues, net | 49,631 | 84,601 | ||||||
OPERATING EXPENSES: | ||||||||
Lease operating | 13,243 | 13,436 | ||||||
Production and ad valorem taxes | 6,943 | 10,182 | ||||||
Depletion, depreciation and amortization | 27,061 | 28,687 | ||||||
Accretion | 223 | 220 | ||||||
Abandonment | 2,882 | 1,092 | ||||||
Impairment of oil and natural gas properties | 111,871 | — | ||||||
General and administrative | 6,566 | 6,049 | ||||||
|
|
|
| |||||
Total operating expenses | 168,789 | 59,666 | ||||||
|
|
|
| |||||
Income (loss) from operations | (119,158 | ) | 24,935 | |||||
OTHER INCOME (EXPENSE): | ||||||||
Gain (loss) on commodity derivatives | 1,604 | (27,271 | ) | |||||
Interest expense, net | (8,867 | ) | (4,913 | ) | ||||
Loss from retirement of long-term debt | (1,080 | ) | — | |||||
Gain on sale of assets | 1,240 | 7 | ||||||
Other gain (loss) | 1,619 | (887 | ) | |||||
|
|
|
| |||||
Total other expense | (5,484 | ) | (33,064 | ) | ||||
|
|
|
| |||||
NET LOSS | $ | (124,642 | ) | $ | (8,129 | ) | ||
|
|
|
| |||||
F-14
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
(in thousands)
| Preferred Equity | Common Equity | Accumulated Deficit | Total | |||||||||||||
BALANCE, JANUARY 1, 2022 | $ | 95,886 | $ | 242,518 | $ | (129,731 | ) | $ | 208,673 | |||||||
Net loss | — | — | (8,129 | ) | (8,129 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
BALANCE, DECEMBER 31, 2022 | 95,886 | 242,518 | (137,860 | ) | 200,544 | |||||||||||
Net loss | — | — | (124,642 | ) | (124,642 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
BALANCE, DECEMBER 31, 2023 | $ | 95,886 | $ | 242,518 | $ | (262,502 | ) | $ | 75,902 | |||||||
|
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|
|
|
|
| |||||||||
F-15
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net loss | $ | (124,642 | ) | $ | (8,129 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities | ||||||||
Depletion, depreciation and amortization | 27,060 | 28,687 | ||||||
Net gain on sale of assets | (1,240 | ) | (7 | ) | ||||
Impairment of oil and natural gas properties | 111,871 | — | ||||||
Amortization of debt issuance costs | 840 | 759 | ||||||
Abandonment | 2,882 | 1,092 | ||||||
Accretion expense | 223 | 220 | ||||||
Commodity derivatives gain | (5,266 | ) | (3,903 | ) | ||||
Loss from retirement of long-term debt | 1,080 | — | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable, net | (2,976 | ) | 7,182 | |||||
Inventory | 110 | 589 | ||||||
Prepaid expenses and other current assets | 623 | 267 | ||||||
Accounts payable and accrued expenses | (850 | ) | (12,464 | ) | ||||
Production taxes payable | 162 | 1,782 | ||||||
Other payables | 3,937 | 906 | ||||||
|
|
|
| |||||
Net cash provided by operating activities | 13,814 | 16,981 | ||||||
|
|
|
| |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Additions to oil and natural gas properties | (9,289 | ) | (11,602 | ) | ||||
Additions to other property, plant and equipment | (18 | ) | (188 | ) | ||||
Proceeds from sales of other assets | 1,431 | 624 | ||||||
|
|
|
| |||||
Net cash used in investing activities | (7,876 | ) | (11,166 | ) | ||||
|
|
|
| |||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from debt | 62,000 | — | ||||||
Repayments on debt | (55,100 | ) | (18,000 | ) | ||||
Debt issuance costs | (3,016 | ) | (1,408 | ) | ||||
|
|
|
| |||||
Net cash provided by (used in) financing activities | 3,884 | (19,408 | ) | |||||
|
|
|
| |||||
Net increase (decrease) in cash and cash equivalents | 9,822 | (13,593 | ) | |||||
Cash and cash equivalents at beginning of year | 1,940 | 15,533 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of year | $ | 11,762 | $ | 1,940 | ||||
|
|
|
| |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-16
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2023 AND 2022
NOTE 1. ORGANIZATIONAND SIGNIFICANT ACCOUNTING POLICIES
Description of Business — The accompanying consolidated financial statements include the accounts of Peak Exploration & Production, LLC, Peak Energy Operating #2, LLC, Peak Powder River Resources, LLC, Willow Springs Development, LLC, and Peak Exploration & Production, Inc. (collectively, the “Company”). The Company is an independent oil and gas company engaged in exploration and development of oil and natural gas assets. The Company conducts its activities in Wyoming. As a Limited Liability Company (“LLC”), the amount of loss at risk for each individual member is limited to the amount of capital contributed to the LLC, and unless otherwise noted, the individual member’s liability for indebtedness of an LLC is limited to the member’s actual capital contribution. The Company will have LLC status until perpetual existence unless it is terminated.
Basis of Presentation — The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and include the accounts of Peak Exploration & Production, LLC, Peak Energy Operating #2, LLC, Peak Powder River Resources, LLC, Willow Springs Development, LLC, and Peak Exploration & Production, Inc. All significant intercompany accounts and transactions have been eliminated in consolidation.
Reclassifications — Certain amounts have been reclassified within the 2023 consolidated statements of operations and the consolidated statement of cash flows for consistency of presentation. These reclassifications did not have a significant impact on the cash flows of the Company.
Use of Estimates — The preparation of consolidated financial statements in accordance with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ significantly from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include timing and costs associated with asset retirement obligations, and oil and gas reserve quantities, which are the basis for the calculation of depreciation, depletion and impairment of oil and natural gas properties.
Cash and Cash Equivalents — Cash and cash equivalents consist of highly liquid investments, with original maturities of three months or less.
Concentrations of Credit Risk — The Company regularly has cash in financial institutions which, at times, may exceed depository insurance limits. The Company places such deposits with high credit quality institutions and has not experienced any credit losses. Substantially all of the Company’s receivables are within the oil and gas industry, primarily from its oil and gas purchasers and joint interest owners. Although diversified within several companies, collectability is largely dependent upon the general economic conditions of the industry.
Accounts Receivable — The Company accrues for oil and natural gas sales based on actual production dates. These are due within 45 days of production. To the extent the Company has joint interest owners in properties, joint interest billings represent monthly billings to working interest owners in the properties the Company operates. Joint interest billings are due within 30 days, with a right of offset against revenues due to working interest owners in the respective properties. The Company determines its allowance for each type of receivable based on the length of time the receivable is past due, its previous loss history, and customers current ability to pay its obligation. The Company also bases its allowance for each type of receivable on its respective credit risks. The Company writes off specific receivables when they become uncollectible. Once an allowance is recorded, any subsequent payments received on such receivables are credited to the allowance for credit losses. To date, the
F-17
Company has not experienced any pattern of credit losses and therefore has no allowance as of December 31, 2023 and 2022. The Company will continually monitor the creditworthiness of its counterparties by reviewing credit ratings, financial statements, and payment history.
Accounting for Oil and Gas Properties — The Company utilizes the successful efforts method of accounting for its oil and gas properties. Leasehold costs, tangible and intangible costs of development wells, and costs of successful exploration wells, are capitalized as incurred. Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Costs of unsuccessful exploration efforts are expensed in the period it is determined that proved reserves were not found and such costs are not recoverable through future revenues. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of development wells are capitalized whether productive or nonproductive. Upon the sale of proved properties, the cost and accumulated depletion are removed from the accounts and any gain or loss is charged to income.
Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one barrel of oil. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the depletion rate (amortizable base divided by beginning of period proved reserves) to current period production.
The Company reviews and evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax reserve cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. An impairment loss is measured as the amount by which asset carrying value exceeds fair value on an individual field-by-field basis.
The Company also performs a review of unproved property costs to determine (i) whether any leases associated with the property have expired or been abandoned, (ii) whether the subject property will be developed or (iii) if the carrying value of the property is not realizable.
Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s depletion rate. These gains and losses are classified as asset dispositions in the consolidated statements of operations.
Partial common operating field sales or dispositions deemed not to significantly alter the depletion rate are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.
F-18
Other Property, Plant and Equipment — Other property, plant and equipment includes buildings, office furniture, transportation equipment and office equipment. Renewals and betterments, which substantially extend the useful lives of the assets, are capitalized. Maintenance and repairs are expensed when incurred. Buildings are stated at cost and depreciated over the estimated useful life of 25 years using straight-line method. Other property and equipment are generally depreciated using the straight-line method over three to seven years. The Company reviews its long-lived assets and property for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of the asset or property. There were no impairments during the years ended December 31, 2023 and 2022.
Other Assets — Other assets consists primarily of water production facilities, operating bonds and yard equipment. Water production facilities are depreciated straight line over a useful life of 10 years.
Revenue Recognition — Revenue from the sale of oil and natural gas are recognized, as the product is delivered to the customers’ custody transfer points and collectability is reasonably assured. The Company fulfills the performance obligations under the customer contracts through daily delivery of oil and natural gas to the customers’ custody transfer points. Revenues are recorded on a monthly basis using the prices received under the Company’s contracts. These contracts are generally derived from stated market prices which are adjusted to reflect deductions, including transportation, fractionation and processing. As a result, the revenues from the sale of oil and natural gas are subject to change with the increase or decrease in market prices. As a result, the sales of oil and natural gas, as presented on the consolidated statements of operations, represent the Company’s share of revenues, net of gathering and processing costs, net of royalties and excluding revenue interests owned by others. When selling oil and natural gas on behalf of royalty owners or working interest owners, the Company acts as an agent and therefore reports the revenue on a net share basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Historically, differences between revenue estimates and actual revenue received have not been significant.
The majority of product sale commitments of the Company are short-term in nature with a contractual term of one year or less. For these contracts, the Company applies the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14, which exempts entities from disclosing the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.
For contracts with terms greater than one-year, the Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in ASC 606-10-50-14A, which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
Debt Issuance Costs — Direct costs incurred by the Company associated with its term loans are capitalized included in the consolidated balance sheets within “long-term debt, net” as of December 31, 2023. Direct costs incurred by the Company associated with its revolving credit facilities are capitalized and included in the consolidated balance sheets within “other assets, net” as of December 31, 2022. These costs are amortized over the life of the applicable credit facility and reported as “interest expense, net” on the consolidated statements of operations.
Income Taxes — Peak Exploration & Production, LLC is an LLC classified as a partnership for U.S. federal income tax purposes. Accordingly, no provision for income tax has been recorded as the income, deductions, expenses, and credits of the Company are reported on the income tax returns of the Company’s members.
F-19
Under professional standards, the Company’s policy is to evaluate the likelihood that its uncertain tax positions will prevail upon examination based on the extent to which those positions have substantial support within the Internal Revenue Code and Regulations, revenue rulings, court decisions and other evidence.
The federal income tax returns of the Company are subject to examination by the Internal Revenue Service (“IRS”), generally for the three years after they were filed. The Company expects no material changes to its unrecognized tax positions within the next 12 months.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. No interest and penalties related to uncertain tax positions were accrued at December 31, 2023.
Fair Value of Financial Instruments — Certain assets and liabilities of the Company are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques and requires that assets and liabilities are classified in their entirety based on the lowest level input that is significant to the fair value measurement. This hierarchy consists of three broad levels:
| • | Level 1 – Observable inputs that are based upon quoted market prices for identical assets and liabilities within active markets. |
| • | Level 2 – Observable inputs other than Level 1 that are based upon quoted market prices for similar assets or liabilities, based upon quoted prices within inactive markets, or inputs other than quoted market prices that are observable through market data for substantially the full term of the asset or liability. |
| • | Level 3 – Inputs that are unobservable for the particular asset or liability due to little or no market activity and are significant to the fair value of the asset or liability. These inputs reflect assumptions that market participants would use when valuing the particular asset or liability. |
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
Because considerable judgment may be required to develop estimates of fair value, the estimates provided may not be indicative of the amounts the Company could realize upon the sale or refinancing of financial instruments.
Share-Based Payments — The Company accounts for stock options through the measurement and recognition of compensation expense for all share-based payment awards to employees and directors based on estimated grant date fair values. The Company accounts for forfeitures of equity-based incentive awards as they occur.
Oil and Natural Gas Revenue Payable — Oil and natural gas revenue payable represents amounts collected by the Company from purchasers of crude oil and natural gas sales due to other revenue interest owners. Generally, the Company is required to remit amounts due within 30 days of the end of the month in which the related production occurred.
Asset Retirement Obligation — The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The Company depletes the amount added to proved oil and natural gas property costs and recognizes accretion expense in connection with the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties.
F-20
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. Revisions to the liability are due to increases in estimated abandonment costs and changes in well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.
Inventory — Inventories consist of tubular goods and other oil and gas related materials valued at the lower of cost or net realizable value, determined by specific identification.
Commodity Derivatives — The Company entered into certain commodity derivative contracts to reduce its exposure to fluctuations in commodity prices related to oil and natural gas production. Derivative instruments are not designated as cash flow hedges for accounting purposes. Unrealized gains and losses on commodity derivative contracts, at fair value, are included on the consolidated balance sheets as either current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Realized gains and losses result from cash settlement of derivative instruments and unrealized changes in the fair values of unsettled derivative instruments are included in other income (expense) in the consolidated statements of operations.
Leases — The Company records a right-of-use asset and a lease liability on the consolidated balance sheets for all leases with terms longer than 12 months. Leases are classified as either finance or operating, with classification affecting the pattern of expense recognition on the statement of operations. The Company determines if an arrangement is a lease at inception. The Company elected the short-term lease recognition exemption for all leases that qualified. Under current lease agreements, there are no residual value guarantees or restrictive lease covenants. In calculating the ROU assets and lease liabilities, several assumptions and judgments were made by the Company, including whether a contract is or contains a lease under the new definition, and the determination of the weighted-average discount rate. Lease liabilities are calculated using a risk-free discount rate.
Leased right-of-use assets are subject to impairment testing as a long-lived asset at the asset-group level. The Company monitors its long-lived assets for indicators of impairment. As the Company’s leased right-of-use assets primarily relate to office facilities and equipment leases, early abandonment of all or part of a facility as part of a restructuring plan is typically an indicator of impairment. If impairment indicators are present, the Company tests whether the carrying amount of the leased right-of-use asset is recoverable including consideration of sublease income, and if not recoverable, measures impairment loss for the right-of-use asset or asset group.
Commitments and Contingencies — Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.
Segments — The crude oil and natural gas and production activities of the Company are solely focused in the United States. The Company has one operating segment and therefore one reporting segment, exploration and production.
Recent Accounting Announcements — In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (“ASU 2020-04”). ASU 2020-04 provides optional guidance for a limited period of time to ease potential accounting impacts associated with transitioning away from reference rates that are expected to be discontinued, such as interbank offered rates and the London Interbank Offered Rate (“LIBOR”). ASU 2020-04 guidance includes practical expedients for
F-21
contract modifications due to reference rate reform. Generally, contract modifications related to reference rate reform may be considered an event that does not require remeasurement or reassessment of a previous accounting determination at the modification date. Further, in December 2023, the FASB issued amendments to extend the period of time preparers can use the reference rate reform relief guidance from December 31, 2023 to December 31, 2024, to address the fact that all LIBOR tenors were not discontinued as of December 31, 2022, and some tenors will be published until June 2023. The Company determined there was no impact from the adoption of ASU-2020-04 on the consolidated financial statements.
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“ASU 2016-13”). ASU 2016-13 requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. ASU 2016-13 is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. In November 2019, the FASB ASU 2019-19, “Codification Improvements to Topic 326: Financial Instruments — Credit Losses”, which makes amendments to clarify the scope of the guidance, including clarification that receivables arising from operating leases are not within its scope. The amended guidance was effective for the Company on January 1, 2023 and did not result in a material impact to the financial position, cash flows, or results of operations.
NOTE 2. ACCOUNTS RECEIVABLE
The following table reflects the components of accounts receivable of the Company (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Oil and natural gas sales | $ | 12,108 | $ | 12,351 | ||||
Joint interest billings | 5,123 | 1,906 | ||||||
Other | 5 | 3 | ||||||
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Gross accounts receivable | 17,236 | 14,260 | ||||||
Allowance for doubtful accounts | — | — | ||||||
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Net accounts receivable | $ | 17,236 | $ | 14,260 | ||||
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Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in the Company’s consolidated balance sheets. As of January 1, 2022, accounts receivable for oil and gas sales was $13.5 million.
NOTE 3. OILAND NATURAL GAS PROPERTIES
The following table reflects the aggregate capitalized costs associated with the Company (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Oil and natural gas properties: | ||||||||
Unproved properties | $ | 30,633 | $ | 33,170 | ||||
Proved properties | 518,703 | 487,569 | ||||||
Work in process | 17,069 | 15,345 | ||||||
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Total oil and natural gas properties | 566,405 | 536,084 | ||||||
Less: Accumulated depreciation, depletion, amortization and impairment | (421,630 | ) | (268,682 | ) | ||||
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Oil and natural gas properties, net | $ | 144,775 | $ | 267,402 | ||||
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F-22
Depletion expense was $26.3 million and $27.3 million for the years ended December 31, 2023 and 2022, respectively. Certain leases associated with unproved property were allowed to expire, resulting in abandonment expenses of $2.9 million and $1.1 million for the years ended December 31, 2023 and 2022, respectively. The Company had no exploratory wells costs during the years ended December 31, 2023 and 2022.
The Company recorded an impairment of oil and natural gas properties of $111.9 million for the year ended December 31, 2023. There was no impairment of oil and natural gas properties for the year ended December 31, 2022.
NOTE 4. REVENUE
The following table presents the disaggregation of oil and natural gas revenue of the Company (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Oil sales | $ | 43,553 | $ | 66,236 | ||||
Natural gas sales | 6,078 | 18,365 | ||||||
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Total oil and natural gas sales, net | $ | 49,631 | $ | 84,601 | ||||
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NOTE 5. OTHER PROPERTY, PLANTAND EQUIPMENT
The following table presents the other property, plant and equipment of the Company (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Building and improvements | $ | 3,175 | $ | 3,175 | ||||
Office furniture and equipment | 1,045 | 1,039 | ||||||
Land | 594 | 594 | ||||||
Transportation equipment | 379 | 367 | ||||||
Other | 29 | 29 | ||||||
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Total property and equipment | 5,222 | 5,204 | ||||||
Less: accumulated depreciation | (3,360 | ) | (3,148 | ) | ||||
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Total property and equipment, net | $ | 1,862 | $ | 2,056 | ||||
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For each of the years ended December 31, 2023 and 2022, the Company recorded depreciation expense for other property and equipment of $0.2 million.
NOTE 6. OTHER ASSETS
The following table presents the other assets of the Company (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Water production facilities | $ | 4,308 | $ | 4,308 | ||||
Debt issuance costs | — | 5,220 | ||||||
Operating bonds | 100 | 200 | ||||||
Yard equipment | 260 | 260 | ||||||
Other | — | 100 | ||||||
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Total property and equipment | 4,668 | 10,088 | ||||||
Less: accumulated depreciation and amortization | (2,667 | ) | (5,751 | ) | ||||
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Total other assets, net | $ | 2,001 | $ | 4,337 | ||||
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F-23
For each of the years ended December 31, 2023 and 2022, the Company recorded depreciation expense on the water production facilities of $0.5 million. For the year ended December 31, 2022, capitalized organizational costs of $1.1 million were written off and included in “other gain (loss)” in the consolidated statements of operations.
NOTE 7. ASSET RETIREMENT OBLIGATIONS
The following table presents changes in asset retirement obligations of the Company (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Asset retirement obligations at beginning of period | $ | 2,491 | $ | 2,265 | ||||
Liabilities incurred | 35 | 6 | ||||||
Liabilities settled and divested | — | — | ||||||
Revision of estimated obligation | — | — | ||||||
Accretion expense on discounted obligation | 223 | 220 | ||||||
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Asset retirement obligations at end of period | $ | 2,749 | $ | 2,491 | ||||
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NOTE 8. COMMODITY DERIVATIVES
Derivative Financial Instruments — The Company’s primary market exposure is to adverse fluctuations in the prices of crude oil. The primary objective of the Company’s risk management policy is to preserve and enhance the value of the Company’s production. The Company uses derivative instruments, primarily swap and collar contracts, to manage the price risk associated with oil production and the resulting impact on cash flow and revenues. The Company’s management is responsible for approving risk management policies and for establishing the Company’s overall risk mitigation. Management is responsible for proposing hedge recommendations, execution of the approved hedging plan, oversight of the risk management process including methodologies used for valuation and risk measurement.
Derivative instruments expose the Company to counterparty credit risk. The Company enters into these contracts with a major financial institution that it considers creditworthy. In addition, the Company’s agreements reduce credit risk by permitting the Company to net settle for transactions with the same counterparty.
As with most derivative instruments, the Company’s derivative contracts contain provisions that may allow another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond.
The terms of the Company’s agreements provide for offsetting of amounts owed or owing between it and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparty has the right to offset amounts owed or owing under that and any other agreement between the parties. The Company’s accounting policy is to offset these positions in its accompanying consolidated balance sheets.
F-24
The Company had the following outstanding commodity derivative financial instruments outstanding at December 31, 2023:
| Year Ended December 31, | ||||||||||||||||
| 2024 | 2025 | 2026 | 2027 | |||||||||||||
Natural gas swaps: | ||||||||||||||||
Notional volume (MMBtu) | 1,134,473 | 859,686 | 563,780 | 284,726 | ||||||||||||
Weighted average swap price ($/MMBtu) | $ | 3.60 | $ | 3.63 | $ | 3.62 | $ | 3.71 | ||||||||
Natural gas collars: | ||||||||||||||||
Notional volume (MMBtu) | 195,028 | 166,467 | 215,812 | 78,272 | ||||||||||||
Weighted average ceiling price ($/MMBtu) | $ | 4.00 | $ | 4.18 | $ | 4.29 | $ | 4.43 | ||||||||
Weighted average floor price ($/MMBtu) | $ | 3.03 | $ | 3.21 | $ | 3.32 | $ | 3.45 | ||||||||
Oil swaps: | ||||||||||||||||
Notional volume (Bbl) | 284,098 | 299,678 | 199,839 | 76,290 | ||||||||||||
Weighted average swap price ($/Bbl) | $ | 69.57 | $ | 65.65 | $ | 63.16 | $ | 63.23 | ||||||||
Oil collars: | ||||||||||||||||
Notional volume (Bbl) | 147,930 | 22,286 | 45,746 | 39,425 | ||||||||||||
Weighted average ceiling price ($/Bbl) | $ | 78.71 | $ | 72.00 | $ | 68.61 | $ | 66.06 | ||||||||
Weighted average floor price ($/Bbl) | $ | 67.76 | $ | 62.24 | $ | 58.80 | $ | 56.06 | ||||||||
Derivative Gains and Losses — Cash receipts and payments reflect the gains or losses on derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The derivative contracts of the Company are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses represent the change in fair value of derivative instruments which continued to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
The following table summarizes the commodity derivative activity of the Company (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Cash paid on derivatives | $ | (3,662 | ) | $ | (31,174 | ) | ||
Non-cash gain on derivatives | 5,266 | 3,903 | ||||||
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Gain (loss) on commodity derivatives | $ | 1,604 | $ | (27,271 | ) | |||
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Financial Statement Presentation — All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the consolidated balance sheets. The Company determines the current and long-term classification based on the timing of expected future cash flows of individual trades. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis in the consolidated balance sheets.
F-25
The following table presents the fair value of the commodity derivative instruments of the Company on a gross basis and on a net basis as presented in the consolidated balance sheets for the periods indicated (in thousands):
| December 31, 2023 | ||||||||||||
| Gross Fair Value | Amounts Netted | Net Fair Value | ||||||||||
Commodity derivative assets: | ||||||||||||
Commodity derivative asset, current | $ | 1,043 | $ | (347 | ) | $ | 696 | |||||
Commodity derivative asset, noncurrent | — | — | — | |||||||||
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Total commodity derivative assets | $ | 1,043 | $ | (347 | ) | $ | 696 | |||||
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Commodity derivative liabilities: | ||||||||||||
Commodity derivative liability, current | $ | (347 | ) | $ | 347 | $ | — | |||||
Commodity derivative liability, noncurrent | (1,191 | ) | — | (1,191 | ) | |||||||
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Total commodity derivative liabilities | $ | (1,538 | ) | $ | 347 | $ | (1,191 | ) | ||||
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| December 31, 2022 | ||||||||||||
| Gross Fair Value | Amounts Netted | Net Fair Value | ||||||||||
Commodity derivative assets: | ||||||||||||
Commodity derivative asset, current | $ | — | $ | — | $ | — | ||||||
Commodity derivative asset, noncurrent | — | — | — | |||||||||
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Total commodity derivative assets | $ | — | $ | — | $ | — | ||||||
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Commodity derivative liabilities: | ||||||||||||
Commodity derivative liability, current | $ | 5,587 | $ | — | $ | 5,587 | ||||||
Commodity derivative liability, noncurrent | 173 | — | 173 | |||||||||
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Total commodity derivative liabilities | $ | 5,760 | $ | — | $ | 5,760 | ||||||
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NOTE 9. FAIR VALUE MEASUREMENTS
The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, long-term debt, and derivatives. The carrying value of cash and cash equivalents, trade receivables, and trade payables and accrued liabilities are considered to be representative of their fair market value due to the short maturity of these instruments.
The Company’s debt is subject to variable interest rates and accordingly its carrying value is considered to be representative of its fair market value.
The following table provides the carrying value and fair value measurement information for certain of the financial assets and liabilities of the Company (in thousands):
| Fair Value Measurements Using: | ||||||||||||||||||||
| Carrying Amount | Total Fair Value | Level 1 Inputs | Level 2 Inputs | Level 3 Inputs | ||||||||||||||||
December 31, 2023 assets (liabilities): | ||||||||||||||||||||
Commodity derivatives | $ | (495 | ) | $ | (495 | ) | $ | — | $ | (495 | ) | $ | — | |||||||
December 31, 2022 assets (liabilities): | ||||||||||||||||||||
Commodity derivatives | $ | (5,760 | ) | $ | (5,760 | ) | $ | — | $ | (5,760 | ) | $ | — | |||||||
The following methods and assumptions were used to estimate the fair values in the table above.
F-26
Level 2 Fair Value Measurements
Commodity derivatives — The fair value of commodity derivatives is estimated using observable market data and assumptions with adjustments based on widely accepted valuation techniques. A discounted cash flow analysis on the expected cash flows of each derivative reflects the contractual terms of the derivative, including period to maturity, and uses observable market-based inputs, including interest rate curves, implied volatilities and credit risk.
Assets Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities of the Company are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets and liabilities.
Asset retirement obligations — The fair value of asset retirement obligations is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation, estimated plugging and abandonment costs, timing of remediation, the credit-adjusted risk-free rate and inflation rate. Significant unobservable inputs (Level 3) utilized in the determination of asset retirement obligations include estimated plugging and abandonment costs of approximately $0.1 million per well, the timing of remediation, which is estimated based on the aggregate average useful life of the Company’s wells, and the credit adjusted risk free rate.
Proved oil and Natural Gas Reserves — The Company’s estimates of proved and proved developed reserves are the major component of its impairment calculations for oil and natural gas properties. The Company reviews and evaluates its oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. If there is an indication the carrying amount of oil and natural gas properties may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax reserve cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The Company’s proved reserves represent the element of these calculations that require various subjective judgments. Estimates of proved reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. These forecasts rely heavily on historical experience of production results, incurred capital costs, operating expenses and workover experience, among other factors. An impairment loss is measured as the amount by which asset carrying value exceeds fair value on an individual field-by-field basis.
NOTE 10. DEBT AND RELATED EXPENSES
The following table presents the outstanding debt and related expenses of the Company (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Wells Fargo Credit Facility | $ | — | $ | 7,000 | ||||
Senior Secured Second Lien | — | 45,000 | ||||||
Fortress Credit Agreement | 58,900 | — | ||||||
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Total debt, including current portion | 58,900 | 52,000 | ||||||
Debt issuance costs | (2,935 | ) | — | |||||
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Total debt, including current portion, net | 55,965 | 52,000 | ||||||
Less: current portion of debt | 6,200 | — | ||||||
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Long-term debt, net | $ | 49,765 | $ | 52,000 | ||||
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F-27
Debt maturities as of December 31, 2023, including current portion, are as follows (in thousands):
2024 | $ | 4,650 | ||
2025 | 6,200 | |||
2026 | 6,200 | |||
2027 | 41,850 | |||
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Total | $ | 58,900 | ||
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Wells Fargo Credit Facility — In June 2019, the Company entered into the third amended and restated credit agreement with Wells Fargo Bank, NA for a Senior Secured Revolving Credit Facility (“Credit Facility”).
In February 2022, the Company entered into a new amendment that increased the borrowing base to $24.0 million. The Credit Facility was due May 2023, bore interest at 2.85% at December 31, 2022 and the Company recorded interest expense of $0.8 million for the year ended December 31, 2022. The Credit Facility was repaid in full during January 2023 by the Fortress Credit Agreement, as discussed below.
Senior Secured Second Lien — On November 16, 2018, the Company entered into a Senior Secured Second Lien Note Purchase Agreement (“NPA”) with Allianz Global Investors GMBH and other lenders, with US Bank, NA acting as the administrative agent. The NPA matured on November 16, 2023, and bore interest at a rate of LIBOR plus 6.75% rate, which averaged 9.00% for the year ended December 31, 2022. For the year ended December 31, 2022, the Company recorded interest expense of $4.1 million for the NPA. The NPA was repaid in full during January 2023 by the Fortress Credit Agreement, as discussed below.
Fortress Credit Agreement — On January 31, 2023, the Company (“Borrower”) entered into a new Credit and Guaranty Agreement with Fortress Credit Corp. (“Credit Agreement”) with initial loan commitments of $62.0 million provided by Fortress Credit Corp. and Cargill, Incorporated (collectively, the “Lenders”). Upon execution of the Credit Agreement, the Company was issued a new term loan with the Lenders for the full commitment amount of $62.0 million which matures on January 31, 2027 (“Maturity Date”). Proceeds from the new loan were utilized to repay in full the existing Credit Facility and NPA, as well as debt issuance costs. The remaining unused proceeds served as additional cash to the Company’s consolidated balance sheet.
Initially, the obligations under the Credit Agreement are guaranteed by certain of the Borrower’s subsidiaries (the “Guarantors”) and the Credit Agreement is secured by substantially all of the assets owned by the Company and the Guarantors (subject to customary exceptions). Borrowings outstanding under the Credit Agreement will initially be Term SOFR Loans (as defined in the Credit Agreement) which bear interest at a rate equal to the sum of (i) the Term SOFR Rate for a three-month interest period, plus 0.15% (“Adjusted Term SOFR Rate”); and (ii) 8.00% per annum. The Administrative Agent (permitted only as expressly set forth in Section 2.07 of the Credit Agreement), may convert any outstanding Term SOFR Loan to an ABR Loan (as defined in the Credit Agreement). Borrowings constituting ABR Loans shall bear interest at a rate equal to the sum of (i) the Alternate Base Rate, defined as the greater of (a) the Prime Rate and (b) the NYFRB Rate plus 0.50%; and (ii) 7.00% per annum. Interest accrued on all outstanding loans is payable at the end of each quarter, through the Maturity Date.
The Company is required to repay to the Lenders an amount equal to 2.50% of the aggregate principal amount of the outstanding loans, including accrued interest, on the last day of each quarter. Furthermore, the Company is subject to mandatory repayment provisions, including in the event of default where the Lenders elect to accelerate amounts due. The Credit Agreement further outlines the ability to prepay the loans in whole, or in part, at the option of the Company. In the event of any repayment or prepayment of the loans, the Company shall immediately pay the applicable premium (as defined in the Credit Agreement) and all accrued interest.
The Credit Agreement contains restrictive covenants that limit the Company’s ability to, among other things: (i) incur additional indebtedness; (ii) incur liens; (iii) enter into mergers; (iv) dispose of assets; (v) engage
F-28
in new business type; (vi) make any investments; (vii) enter into certain swap agreements; (viii) make restrictive payments; and (ix) engage in certain transactions with affiliates. These restrictive covenants are subject to a number of important exceptions and qualifications.
In addition, the Credit Agreement requires the Company to maintain compliance with the following financial ratios determined as of the last day of the quarter: (A) a current ratio (as defined in the Credit Agreement) of no less than 1.00 to 1.00; (B) a PDP asset coverage ratio (as defined in the Credit Agreement) of no less than 1.75 to 1.00; (C) a leverage ratio (as defined in the Credit Agreement) of no more than 2.75 to 1.00; and (D) liquidity (as defined in the Credit Agreement) of not less than $5.0 million. Furthermore, for any year, general and administrative expenses (as defined in the Credit Agreement) attributable to the Company must not exceed $8.5 million. The Company was not in compliance with the current ratio as of December 31, 2023. However, on April 11, 2024, the Company received a waiver related to non-compliance with the current ratio. As of December 31, 2023, the Company was in compliance with all other covenants outlined above. On April 24, 2024, the Company entered into the First Amendment to the Credit Agreement, which moved the payment date for the required quarterly principal and interest payments to the first business day of the immediately succeeding quarter.
NOTE 11. EQUITYAND SHARE BASED COMPENSATION
Preferred Equity — The Company has issued 958,864 units of preferred shares for cash totaling $95.9 million as of December 31, 2023 and 2022. The Company has not issued any preferred shares since 2018. The preferred shares include the following characteristics and rights:
| • | When declared, the Company shall pay distributions in cash to the holders of the preferred shares in the amount of 6.0% per annum, paid in arrears. |
| • | All or a portion of the preferred shares and accrued but unpaid interest can be converted into common units at a price of $65.00 per unit, or the conversion price then in effect at the time of conversion. |
| • | Each holder of the preferred shares is entitled to one vote per preferred share. |
| • | The preferred shares include a liquidation preference over common units. |
The preferred shares may not demand repayment of the equity or accrued dividends, and if not converted to common units, once the amount of the preferred shares and all accrued dividends has been paid, the holders have no additional rights or claims to the assets of the Company. For the years ended December 31, 2023 and 2022 no dividends have been declared, therefore, are not recorded on the consolidated balance sheets. As of December 31, 2023 and 2022, the balance of the accumulated undeclared distributions totaled $43.9 million and $38.2 million, respectively. The accumulated liquidation preference as of December 31, 2023 and 2022 totaled $139.8 million and $134.0 million, respectively.
Share Based Compensation — The Company has a total of 101,140 options outstanding for the years ended December 31, 2023 and 2022. The options are exercisable at a price of $100 per option. There were no options granted, forfeited or exercised for the years ended December 31, 2023 and 2022 and the Company had no compensation expense for the years ended December 31, 2023 and 2022.
The approximate remaining weighted-average contractual term of options outstanding at December 31, 2023 is approximately five years. At December 31, 2023, all options were vested and the Company had no unrecognized share-based compensation expense.
F-29
NOTE 12. LEASES
The following table summarizes the operating leases of the Company for the periods indicated (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Operating lease expenses | $ | 131 | $ | 133 | ||||
Cash paid for operating lease liabilities | $ | 131 | $ | 133 | ||||
Right-of-use assets obtained in exchange for operating lease liabilities | $ | — | $ | 622 | ||||
Amortization of right-of-use assets | $ | 144 | $ | 144 | ||||
Lease liability balance | $ | 499 | $ | 622 | ||||
Weighted-average discount rate (%) | 1.37 | 1.37 | ||||||
Weighted-average remaining lease term (years) | 3.6 | 4.5 | ||||||
Total expense for all leases for the years ended December 31, 2023 and 2022 was $1.8 million and $1.3 million, respectively.
Future minimum annual lease payments as of December 31, 2023 are as follows (in thousands):
2024 | $ | 151 | ||
2025 | 141 | |||
2026 | 131 | |||
2027 | 88 | |||
2028 | — | |||
Thereafter | — | |||
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| |||
Total lease payments | 511 | |||
Less: interest | (12 | ) | ||
|
| |||
Present value of lease liabilities | $ | 499 | ||
|
|
NOTE 13. COMMITMENTS AND CONTINGENCIES
Environmental Matters — Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the operations and the cost of crude oil and natural gas exploration, development, and production operations of the Company. The Company does not anticipate that it will be required in the near future to expend significant amounts for compliance with such federal, state and local laws and regulations, and therefore, no amounts have been accrued for such purposes. At December 31, 2023 and 2022, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company.
Government Regulation — Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters, including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2023 and 2022, the Company has not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition, capital expenditures, earnings, or competitive position of the Company in the oil and gas industry.
F-30
Litigation — The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect any such matters to have a material effect on its financial condition, results of operations or cash flows.
NOTE 14. RELATED PARTY TRANSACTIONS
The Company is subject to an Administrative Service Agreement (“ASA”) with Peak BLM Lease, LLC (“Peak BLM”), an affiliate, that specifies the Company will perform administrative duties associated with Peak BLM’s properties. Per the ASA, Peak BLM is to pay the Company approximately $0.1 million monthly. For the years ended December 31, 2023, and 2022, Peak BLM paid the Company $1.8 million and $1.2 million, respectively, and are generally reflected as a reduction to “general and administrative” on the accompany consolidated statements of operations. For the year ended December 31, 2023, $0.6 million of amounts paid to the Company were for services to be provided in 2024, and is therefore included within “accounts payable and accrued expenses” on the consolidated balance sheet at December 31, 2023. In addition, the Company performs as the administrator of one jointly owned well, which resulted in Peak BLM paying $0.4 million and $5.0 million for the years ended December 31, 2023 and 2022, respectively, for capital expenditures and/or lease operating expenses. There were no other related party balances for the years ended December 31, 2023, and 2022.
NOTE 15. SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides certain supplemental cash flow information for the periods indicated (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Supplemental Disclosure of Cash Flow Information: | ||||||||
Cash paid for interest | $ | 8,841 | $ | 4,734 | ||||
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| |||||
Supplemental Disclosure of Non-Cash Information: | ||||||||
Oil and natural gas additions through accounts payable and accrued expenses | $ | 9,246 | $ | 2,610 | ||||
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|
| |||||
Right-of-use asset obtained in exchange for operating lease liabilities | $ | — | $ | 622 | ||||
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| |||||
Revisions and additions to asset retirement obligations | $ | 35 | $ | 6 | ||||
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NOTE 16. SUBSEQUENT EVENTS
In preparing the accompanying consolidated financial statements of the Company, management has evaluated all subsequent events and transactions for potential recognition or disclosure through the date the consolidated financial statements of the Company were available for issuance. All subsequent events requiring recognition have been incorporated into these consolidated financial statements.
* * * * *
F-31
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)
DECEMBER 31, 2023 AND 2022
NOTE 17. SUPPLEMENTAL OILAND NATURAL GAS INFORMATION (UNAUDITED)
Supplemental unaudited information regarding the Company’s oil and natural gas activities is presented in this note. All of the Company’s oil and natural gas reserves are located in the U.S.
Costs Incurred — The following table reflects the costs incurred in oil and natural gas property acquisition, exploration, and development activities (in thousands):
| For the Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Property acquisition costs: | ||||||||
Proved properties | $ | — | $ | — | ||||
Unproved properties | — | — | ||||||
Exploration costs | — | — | ||||||
Development costs | 9,396 | 11,602 | ||||||
|
|
|
| |||||
Costs incurred | $ | 9,396 | $ | 11,602 | ||||
|
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| |||||
Results of Operations — The following table includes revenues and expenses associated with the Company’s oil and natural gas producing activities (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Oil and natural gas sales, net | $ | 49,631 | $ | 84,601 | ||||
Lease operating | (13,243 | ) | (13,436 | ) | ||||
Depletion, depreciation and amortization expense | (27,901 | ) | (28,687 | ) | ||||
Accretion | (223 | ) | (220 | ) | ||||
Impairment of oil and natural gas properties | (111,871 | ) | — | |||||
Abandonment | (2,882 | ) | (1,092 | ) | ||||
|
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| |||||
Results of operations | $ | (106,489 | ) | $ | 41,166 | |||
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| |||||
Estimated Quantities of Proved Oil and Natural Gas Reserves — Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with the changes in prices and operating costs. Reserve estimates are inherently imprecise and those estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
F-32
A summary of the Company’s change in quantities of proved oil and natural gas reserves for the years ended December 31, 2023 and 2022 are as follows:
| Year ended December 31, 2023 | ||||||||||||||||
| Oil (Bbl) | Natural Gas (Mcf) | Liquids* (Bbl) | Total Boe | |||||||||||||
Proved reserves as of December 31, 2022 | 6,929,652 | 35,244,352 | — | 12,803,711 | ||||||||||||
Revisions of previous estimates | (1,588,707 | ) | (6,047,568 | ) | — | (2,596,635 | ) | |||||||||
Extensions, discoveries and other additions | 249,775 | 1,614,283 | — | 518,822 | ||||||||||||
Production | (571,769 | ) | (2,484,069 | ) | — | (985,781 | ) | |||||||||
Purchases (sales) of minerals in place | (8,163 | ) | (92,154 | ) | — | (23,522 | ) | |||||||||
|
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|
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| |||||||||
Proved reserves as of December 31, 2023 | 5,010,788 | 28,234,844 | — | 9,716,595 | ||||||||||||
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Proved developed reserves | ||||||||||||||||
Beginning of year | 5,358,626 | 23,079,409 | — | 9,205,194 | ||||||||||||
End of year | 4,305,614 | 20,374,318 | — | 7,701,334 | ||||||||||||
Proved undeveloped reserves | ||||||||||||||||
Beginning of year | 1,571,026 | 12,164,943 | — | 3,598,517 | ||||||||||||
End of year | 705,174 | 7,860,526 | — | 2,015,261 | ||||||||||||
| Year ended December 31, 2022 | ||||||||||||||||
| Oil (Bbl) | Natural Gas (Mcf) | Liquids* (Bbl) | Total Boe | |||||||||||||
Proved reserves as of December 31, 2021 | 7,340,268 | 40,960,100 | — | 14,166,951 | ||||||||||||
Revisions of previous estimates | (105,757 | ) | (3,987,422 | ) | — | (770,327 | ) | |||||||||
Extensions, discoveries and other additions | 405,435 | 1,153,607 | — | 597,703 | ||||||||||||
Production | (710,294 | ) | (2,881,933 | ) | — | (1,190,616 | ) | |||||||||
Purchases (sales) of minerals in place | — | — | — | — | ||||||||||||
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Proved reserves as of December 31, 2022 | 6,929,652 | 35,244,352 | — | 12,803,711 | ||||||||||||
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Proved developed reserves | ||||||||||||||||
Beginning of year | 5,860,388 | 30,219,550 | — | 10,896,980 | ||||||||||||
End of year | 5,358,626 | 23,079,409 | — | 9,205,194 | ||||||||||||
Proved undeveloped reserves | ||||||||||||||||
Beginning of year | 1,479,880 | 10,740,550 | — | 3,269,971 | ||||||||||||
End of year | 1,571,026 | 12,164,943 | — | 3,598,517 | ||||||||||||
| * | The Company has not historically separately reported reserve quantities for liquids |
For the year ended December 31, 2023, extensions, discoveries and other additions resulted primarily from thirty-six new wells drilled for 517,531 Boe. Revisions for the year ended December 31, 2023 were largely driven by lower commodity prices during the year, which negatively impacted proved reserves by approximately 2,800 Mboe. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first day of the month spot prices prior to the end of the reporting period. These SEC prices decreased for oil by 16.5% and for natural gas by 58.5% from December 31, 2022 to December 31, 2023. Lower commodity prices decrease the overall value of proved reserves along with the amount of economically recoverable reserves quantities. Partially offsetting the decrease in SEC oil and natural gas prices were additional analogs for our proved undeveloped reserves, which resulted in an increase to proved undeveloped reserve volumes of approximately 200 Mboe. As additional wells are developed, we utilize these wells as an analog for our undeveloped proved reserves, which can result in a slightly higher or lower expected volumes when these proved undeveloped reserves are ultimately developed.
F-33
For the year ended December 31, 2022, extensions, discoveries and other additions resulted from twelve new wells drilled for 200,483 Boe and the addition of two proved undeveloped locations for 291,838 Boe. Revisions for the year ended December 31, 2022 were largely driven by a 19.9% increase in estimated lease operating expenses as a result of inflationary factors and downward revisions to three wells as a result of mud invasion from offset wells.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions.
Proved reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”), which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first day of the month spot prices prior to the end of the reporting period. These SEC prices as of December 31, 2023 and 2022 were $78.22 and $93.67 per barrel of oil and $2.64 and $6.36 per MMBtu of natural gas, respectively.
The estimated realized prices used in computing the Company’s reserves as of December 31, 2023 were as follows: (i) $77.16 per barrel of oil, and (ii) $2.66 per Mcf of natural gas. The estimated realized prices used in computing the Company’s reserves as of December 31, 2022 were as follows: (i) $92.13 per barrel of oil, and (ii) $6.67 per Mcf of natural gas.
All realized prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the “as of date” forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses would have been computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the oil and natural gas properties of the Company. The estimated future net cash flows are then discounted at a rate of 10.0%.
The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods presented (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Future cash inflows | $ | 461,643 | $ | 873,430 | ||||
Future production costs | (229,284 | ) | (353,202 | ) | ||||
Future development and abandonment costs | (29,650 | ) | (46,872 | ) | ||||
Future income taxes | — | — | ||||||
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Future net cash flows | 202,709 | 473,356 | ||||||
10% annual discount for estimated timing of cash flows | (87,145 | ) | (214,220 | ) | ||||
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Standardized measure of discounted future net cash flows | $ | 115,564 | $ | 259,136 | ||||
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It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the proved reserves of the Company. The disclosures shown are based on estimates of
F-34
proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10.0% discount rate is set by regulators. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods presented (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Standardized measure of discounted future net cash flows at January 1 | $ | 259,136 | $ | 191,080 | ||||
Net change in prices and production costs | (90,493 | ) | 122,932 | |||||
Changes in estimated future development and abandonment costs | 589 | (4,901 | ) | |||||
Sales of crude oil and natural gas produced, net of production costs | (29,465 | ) | (60,983 | ) | ||||
Extensions, discoveries and improved recoveries, less related costs | 7,096 | 12,369 | ||||||
Purchases (sales) of minerals in place, net | (195 | ) | — | |||||
Revisions of previous quantity estimates | (49,082 | ) | (10,785 | ) | ||||
Development costs incurred during the period | — | 4,410 | ||||||
Change in income taxes | — | — | ||||||
Accretion of discount | 25,913 | 19,108 | ||||||
Change in timing of estimated future production and other | (7,935 | ) | (14,094 | ) | ||||
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Net change | (143,572 | ) | 68,056 | |||||
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Standardized measure of discounted future net cash flows at December 31 | $ | 115,564 | $ | 259,136 | ||||
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Estimates of economically recoverable oil and natural gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.
* * * * *
F-35
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands)
| June 30, 2024 | December 31, 2023 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 8,099 | $ | 11,762 | ||||
Accounts receivable, net | 10,995 | 17,236 | ||||||
Prepaid expenses and other current assets | 643 | 218 | ||||||
Commodity derivatives | 550 | 696 | ||||||
Inventories | 98 | 97 | ||||||
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Total current assets | 20,385 | 30,009 | ||||||
Oil and natural gas property and equipment, based on successful efforts method of accounting, net | 134,726 | 144,775 | ||||||
Other property, plant and equipment, net | 1,782 | 1,862 | ||||||
Right-of-use assets | 405 | 478 | ||||||
Other assets, net | 1,776 | 2,001 | ||||||
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Total assets | $ | 159,074 | $ | 179,125 | ||||
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LIABILITIES AND MEMBERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued expenses | $ | 4,668 | $ | 14,365 | ||||
Production and ad valorem taxes payable | 2,853 | 3,322 | ||||||
Oil and natural gas revenue payable | 10,173 | 15,936 | ||||||
Commodity derivatives | 3,560 | — | ||||||
Right-of-use liabilities | 147 | 160 | ||||||
Current portion of long-term debt | 6,200 | 6,200 | ||||||
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Total current liabilities | 27,601 | 39,983 | ||||||
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Long-term debt, net | 48,610 | 49,765 | ||||||
Other noncurrent liabilities: | ||||||||
Asset retirement obligation | 2,863 | 2,749 | ||||||
Ad valorem taxes | 9,196 | 9,197 | ||||||
Commodity derivatives | 4,241 | 1,191 | ||||||
Right-of-use liabilities | 280 | 338 | ||||||
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Total other noncurrent liabilities | 16,580 | 13,475 | ||||||
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Total liabilities | 92,791 | 103,223 | ||||||
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Commitments and contingencies | ||||||||
Members’ equity: | ||||||||
Preferred equity | 95,886 | 95,886 | ||||||
Common equity | 242,518 | 242,518 | ||||||
Accumulated deficit | (272,121 | ) | (262,502 | ) | ||||
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Total members’ equity | 66,283 | 75,902 | ||||||
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Total liabilities and members’ equity | $ | 159,074 | $ | 179,125 | ||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
F-36
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands)
| Six Months Ended June 30, | ||||||||
| 2024 | 2023 | |||||||
REVENUES: | ||||||||
Oil and natural gas sales, net | $ | 22,977 | $ | 25,265 | ||||
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Total revenues, net | 22,977 | 25,265 | ||||||
OPERATING EXPENSES: | ||||||||
Lease operating | 6,050 | 6,506 | ||||||
Production and ad valorem taxes | 3,057 | 3,678 | ||||||
Depletion, depreciation and amortization | 6,555 | 12,139 | ||||||
Accretion | 114 | 111 | ||||||
Abandonment | 1,921 | 2,863 | ||||||
General and administrative | 3,606 | 3,436 | ||||||
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Total operating expenses | 21,303 | 28,733 | ||||||
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Income (loss) from operations | 1,674 | (3,468 | ) | |||||
OTHER INCOME (EXPENSE): | ||||||||
Gain (loss) on commodity derivatives | (6,992 | ) | 3,573 | |||||
Interest expense, net | (4,330 | ) | (4,193 | ) | ||||
Loss from retirement of long-term debt | — | (1,089 | ) | |||||
Gain (loss) on sale of assets | (23 | ) | 1,203 | |||||
Other gain | 52 | 1,293 | ||||||
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Total other income (expense) | (11,293 | ) | 787 | |||||
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NET LOSS | $ | (9,619 | ) | $ | (2,681 | ) | ||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
F-37
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY (UNAUDITED)
(in thousands)
| Preferred Equity | Common Equity | Accumulated Deficit | Total | |||||||||||||
BALANCE, JANUARY 1, 2024 | $ | 95,886 | $ | 242,518 | $ | (262,502 | ) | $ | 75,902 | |||||||
Net loss | — | — | (9,619 | ) | (9,619 | ) | ||||||||||
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BALANCE, JUNE 30, 2024 | $ | 95,886 | $ | 242,518 | $ | (272,121 | ) | $ | 66,283 | |||||||
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| Preferred Equity | Common Equity | Accumulated Deficit | Total | |||||||||||||
BALANCE, JANUARY 1, 2023 | $ | 95,886 | $ | 242,518 | $ | (137,860 | ) | $ | 200,544 | |||||||
Net loss | — | — | (2,681 | ) | (2,681 | ) | ||||||||||
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BALANCE, JUNE 30, 2023 | $ | 95,886 | $ | 242,518 | $ | (140,541 | ) | $ | 197,863 | |||||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
F-38
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
| Six Months Ended June 30, | ||||||||
| 2024 | 2023 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net loss | $ | (9,619 | ) | $ | (2,681 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities | ||||||||
Depletion, depreciation and amortization | 6,555 | 12,139 | ||||||
Net (gain) loss on sale of assets | 23 | (1,203 | ) | |||||
Amortization of debt issuance costs | 475 | 343 | ||||||
Abandonment | 1,921 | 2,863 | ||||||
Accretion expense | 114 | 112 | ||||||
Commodity derivatives (gain) loss | 6,756 | (5,932 | ) | |||||
Loss from retirement of long-term debt | — | 1,089 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable, net | 6,241 | (437 | ) | |||||
Inventory | (1 | ) | 122 | |||||
Prepaid expenses and other current assets | (425 | ) | (18 | ) | ||||
Accounts payable and accrued expenses | (8,944 | ) | 3,379 | |||||
Production taxes payable | (469 | ) | (669 | ) | ||||
Other payables | (5,837 | ) | (4,207 | ) | ||||
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| |||||
Net cash provided by (used in) operating activities | (3,210 | ) | 4,900 | |||||
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| |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Additions to oil and natural gas properties | (2,054 | ) | (7,857 | ) | ||||
Additions to other property, plant and equipment | (12 | ) | (17 | ) | ||||
Proceeds from sales of other assets | 3,243 | 1,339 | ||||||
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| |||||
Net cash used in investing activities | 1,177 | (6,535 | ) | |||||
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CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from debt | — | 62,000 | ||||||
Repayments on debt | (1,550 | ) | (52,000 | ) | ||||
Debt issuance costs | (80 | ) | (3,044 | ) | ||||
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| |||||
Net cash provided by (used in) financing activities | (1,630 | ) | 6,956 | |||||
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| |||||
Net increase (decrease) in cash and cash equivalents | (3,663 | ) | 5,321 | |||||
Cash and cash equivalents at beginning of period | 11,762 | 1,940 | ||||||
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| |||||
Cash and cash equivalents at end of period | $ | 8,099 | $ | 7,261 | ||||
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The accompanying notes are an integral part of these condensed consolidated financial statements.
F-39
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
NOTE 1. ORGANIZATIONAND SIGNIFICANT ACCOUNTING POLICIES
Description of Business — The accompanying condensed consolidated financial statements include the accounts of Peak Exploration & Production, LLC, Peak Energy Operating #2, LLC, Peak Powder River Resources, LLC, Willow Springs Development, LLC, and Peak Exploration & Production, Inc. (collectively, the “Company”). The Company is an independent oil and gas company engaged in exploration and development of oil and natural gas assets. The Company, at this time, conducts its activities in Wyoming. As a Limited Liability Company (“LLC”), the amount of loss at risk for each individual member is limited to the amount of capital contributed to the LLC, and unless otherwise noted, the individual member’s liability for indebtedness of an LLC is limited to the member’s actual capital contribution. The Company will have LLC status until perpetual existence unless it is terminated.
Basis of Presentation — The unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and include the accounts of Peak Exploration & Production, LLC, Peak Energy Operating #2, LLC, Peak Powder River Resources, LLC, Willow Springs Development, LLC, and Peak Exploration & Production, Inc. All significant intercompany accounts and transactions have been eliminated in consolidation. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2023. Results for the interim periods are not necessarily indicative of results to be expected for the full year ended December 31, 2024. In the opinion of management, these condensed consolidated financial statements reflect all normal recurring adjustments necessary for a fair presentation of the result for the periods indicated.
Reclassifications — Certain amounts have been reclassified within the 2023 consolidated statements of operations and the consolidated statement of cash flows for consistency of presentation. These reclassifications did not have a significant impact on the cash flows of the Company.
Use of Estimates — The preparation of the condensed consolidated financial statements in accordance with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ significantly from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include timing and costs associated with asset retirement obligations, and oil and gas reserve quantities, which are the basis for the calculation of depreciation, depletion and impairment of oil and natural gas properties.
Recent Accounting Announcements — In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (“ASU 2020-04”). ASU 2020-04 provides optional guidance for a limited period of time to ease potential accounting impacts associated with transitioning away from reference rates that are expected to be discontinued, such as interbank offered rates and the London Interbank Offered Rate (“LIBOR”). ASU 2020-04 guidance includes practical expedients for contract modifications due to reference rate reform. Generally, contract modifications related to reference rate reform may be considered an event that does not require remeasurement or reassessment of a previous accounting determination at the modification date. Further, in December 2023, the FASB issued amendments to extend the period of time preparers can use the reference rate reform relief guidance from December 31, 2023 to December 31, 2024, to address the fact that all LIBOR tenors were not discontinued as of December 31, 2022, and some tenors will be published until June 2023. The Company determined there was no impact from the adoption of ASU-2020-04 on the condensed consolidated financial statements.
F-40
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
NOTE 2. ACCOUNTS RECEIVABLE
The following table reflects the components of accounts receivable of the Company (in thousands):
| As of June 30, 2024 | As of December 31, 2023 | |||||||
Oil and natural gas sales | $ | 9,098 | $ | 12,108 | ||||
Joint interest billings | 1,891 | 5,123 | ||||||
Other | 6 | 5 | ||||||
|
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|
| |||||
Gross accounts receivable | 10,995 | 17,236 | ||||||
Allowance for credit losses | — | — | ||||||
|
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| |||||
Net accounts receivable | $ | 10,995 | $ | 17,236 | ||||
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| |||||
Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in the Company’s consolidated balance sheets. The Company has no allowance at June 30, 2024 or December 31, 2023.
NOTE 3. OILAND NATURAL GAS PROPERTIES
The following table reflects the aggregate capitalized costs associated with the Company (in thousands):
| As of June 30, 2024 | As of December 31, 2023 | |||||||
Oil and natural gas properties: | ||||||||
Unproved properties | $ | 31,673 | $ | 30,633 | ||||
Proved properties, net of impairment | 400,296 | 400,495 | ||||||
Work in process, net of impairment | 2,084 | 7,010 | ||||||
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| |||||
Total oil and natural gas properties | 434,053 | 438,138 | ||||||
Less: Accumulated depreciation, depletion and amortization | (299,327 | ) | (293,363 | ) | ||||
|
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| |||||
Oil and natural gas properties, net | $ | 134,726 | $ | 144,775 | ||||
|
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| |||||
Depletion expenses were $6.2 million and $11.7 million for the six months ended June 30, 2024 and 2023, respectively. Abandonment expense in the amount of $2.0 million for the six months ended June 30, 2024 consists of abandonment of a drilled well that will not be completed and certain leases associated with unproved property were allowed to expire. Abandonment expense in the amount of $2.9 million for the six months ended June 30, 2023 consists of certain leases associated with unproved property were allowed to expire. The Company had no exploratory wells costs during the six months ended June 30, 2024 or for the year ended December 31, 2023.
F-41
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
NOTE 4. REVENUE
The following table presents the disaggregation of oil and natural gas revenue of the Company (in thousands):
| Six Months Ended June 30, | ||||||||
| 2024 | 2023 | |||||||
Oil sales | $ | 20,611 | $ | 21,678 | ||||
Natural gas sales | 2,366 | 3,587 | ||||||
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| |||||
Total oil and natural gas sales, net | $ | 22,977 | $ | 25,265 | ||||
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NOTE 5. OTHER PROPERTY, PLANTAND EQUIPMENT
The following table presents the other property, plant and equipment of the Company (in thousands):
| As of June 30, 2024 | As of December 31, 2023 | |||||||
Building and improvements | $ | 3,175 | $ | 3,175 | ||||
Office furniture and equipment | 1,056 | 1,045 | ||||||
Land | 594 | 594 | ||||||
Transportation equipment | 379 | 379 | ||||||
Other | 29 | 29 | ||||||
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| |||||
Total property and equipment | 5,233 | 5,222 | ||||||
Less: accumulated depreciation | (3,451 | ) | (3,360 | ) | ||||
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| |||||
Total property and equipment, net | $ | 1,782 | $ | 1,862 | ||||
|
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| |||||
Depreciation expense for other property, plant and equipment was $0.1 million for the six months ended June 30, 2024 and 2023. There were no impairments of other property, plant and equipment for the six months ended June 30, 2024 and 2023.
NOTE 6. OTHER ASSETS
The following table presents the other assets of the Company (in thousands):
| As of June 30, 2024 | As of December 31, 2023 | |||||||
Water production facilities | $ | 4,308 | $ | 4,308 | ||||
Operating bonds | 100 | 100 | ||||||
Yard equipment | 260 | 260 | ||||||
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| |||||
Total property and equipment | 4,668 | 4,668 | ||||||
Less: accumulated depreciation and amortization | (2,892 | ) | (2,667 | ) | ||||
|
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| |||||
Total other assets, net | $ | 1,776 | $ | 2,001 | ||||
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| |||||
Depreciation expense for other assets was $0.2 million for the six months ended June 30, 2024 and 2023.
F-42
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
NOTE 7. ASSET RETIREMENT OBLIGATIONS
The following table presents changes in asset retirement obligations of the Company (in thousands):
| As of June 30, 2024 | As of December 31, 2023 | |||||||
Asset retirement obligations at beginning of period | $ | 2,749 | $ | 2,491 | ||||
Liabilities incurred | — | 35 | ||||||
Liabilities settled and divested | — | — | ||||||
Revision of estimated obligation | — | — | ||||||
Accretion expense on discounted obligation | 114 | 223 | ||||||
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| |||||
Asset retirement obligations at end of period | $ | 2,863 | $ | 2,749 | ||||
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NOTE 8. COMMODITY DERIVATIVES
Derivative Financial Instruments — The Company’s primary market exposure is to adverse fluctuations in the prices of crude oil. The primary objective of the Company’s risk management policy is to preserve and enhance the value of the Company’s production. The Company uses derivative instruments, primarily swap and collar contracts, to manage the price risk associated with oil production and the resulting impact on cash flow and revenues. The Company’s management is responsible for approving risk management policies and for establishing the Company’s overall risk mitigation. Management is responsible for proposing hedge recommendations, execution of the approved hedging plan, oversight of the risk management process including methodologies used for valuation and risk measurement.
Derivative instruments expose the Company to counterparty credit risk. The Company enters into these contracts with a major financial institution that it considers creditworthy. In addition, the Company’s agreements reduce credit risk by permitting the Company to net settle for transactions with the same counterparty.
As with most derivative instruments, the Company’s derivative contracts contain provisions that may allow another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond.
The terms of the Company’s agreements provide for the offsetting of amounts owed or owing between it and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparty has the right to offset amounts owed or owing under that and any other agreement between the parties. The Company’s accounting policy is to offset these positions in its accompanying condensed consolidated balance sheets.
F-43
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
The Company had the following outstanding commodity derivative financial instruments outstanding at June 30, 2024:
| 2024 | 2025 | 2026 | 2027 | 2028 | ||||||||||||||||
| Natural gas swaps: | ||||||||||||||||||||
Notional volume (MMBtu) | 538,587 | 859,686 | 563,780 | 284,726 | 14,136 | |||||||||||||||
Weighted average swap price ($/MMBtu) | $ | 3.59 | $ | 3.63 | $ | 3.62 | $ | 3.71 | $ | 4.50 | ||||||||||
| Natural gas collars: | ||||||||||||||||||||
Notional volume (MMBtu) | 117,650 | 202,145 | 257,281 | 227,389 | 14,136 | |||||||||||||||
Weighted average ceiling price ($/MMBtu) | $ | 4.13 | $ | 4.16 | $ | 4.27 | $ | 4.22 | $ | 4.30 | ||||||||||
Weighted average floor price ($/MMBtu) | $ | 3.12 | $ | 3.17 | $ | 3.28 | $ | 3.19 | $ | 3.20 | ||||||||||
| Oil swaps: | ||||||||||||||||||||
Notional volume (Bbl) | 129,413 | 299,678 | 202,539 | 97,675 | 4,464 | |||||||||||||||
Weighted average swap price ($/Bbl) | $ | 69.44 | $ | 65.65 | $ | 63.25 | $ | 64.06 | $ | 64.40 | ||||||||||
| Oil collars: | ||||||||||||||||||||
Notional volume (Bbl) | 71,369 | 22,286 | 50,956 | 63,040 | 4,464 | |||||||||||||||
Weighted average ceiling price ($/Bbl) | $ | 74.24 | $ | 72.00 | $ | 69.16 | $ | 67.91 | $ | 69.00 | ||||||||||
Weighted average floor price ($/Bbl) | $ | 64.21 | $ | 62.24 | $ | 59.33 | $ | 57.73 | $ | 58.50 | ||||||||||
Derivative Gains and Losses — Cash receipts and payments reflect the gains or losses on derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The derivative contracts of the Company are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses represent the change in fair value of derivative instruments which continued to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
The following table summarizes the commodity derivative activity of the Company (in thousands):
| Six Months Ended June 30, | ||||||||
| 2024 | 2023 | |||||||
Cash paid on derivatives | $ | (236 | ) | $ | (2,359 | ) | ||
Non-cash gain (loss) on derivatives | (6,756 | ) | 5,932 | |||||
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Gain (loss) on commodity derivatives | $ | (6,992 | ) | $ | 3,573 | |||
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| |||||
Financial Statement Presentation — All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the condensed consolidated balance sheets. The Company determines the current and long-term classification based on the timing of expected future cash flows of individual trades. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis in the consolidated balance sheets.
F-44
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
The following table presents the fair value of the commodity derivative instruments of the Company on a gross basis and on a net basis as presented in the condensed consolidated balance sheets for the periods indicated (in thousands):
| As of June 30, 2024 | ||||||||||||
| Gross Fair Value | Amounts Netted | Net Fair Value | ||||||||||
Commodity derivative assets: | ||||||||||||
Commodity derivative asset, current | $ | 550 | $ | (550 | ) | $ | — | |||||
Commodity derivative asset, noncurrent | — | — | — | |||||||||
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| |||||||
Total commodity derivative assets | $ | 550 | $ | (550 | ) | $ | — | |||||
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Commodity derivative liabilities: | ||||||||||||
Commodity derivative liability, current | $ | (3,560 | ) | $ | 550 | $ | (3,010 | ) | ||||
Commodity derivative liability, noncurrent | (4,241 | ) | — | (4,241 | ) | |||||||
|
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| |||||||
Total commodity derivative liabilities | $ | (7,801 | ) | $ | 550 | $ | (7,251 | ) | ||||
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| As of December 31, 2023 | ||||||||||||
| Gross Fair Value | Amounts Netted | Net Fair Value | ||||||||||
Commodity derivative assets: | ||||||||||||
Commodity derivative asset, current | $ | 1,043 | $ | (347 | ) | $ | 696 | |||||
Commodity derivative asset, noncurrent | — | — | — | |||||||||
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| |||||||
Total commodity derivative assets | $ | 1,043 | $ | (347 | ) | $ | 696 | |||||
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Commodity derivative liabilities: | ||||||||||||
Commodity derivative liability, current | $ | (347 | ) | $ | 347 | $ | — | |||||
Commodity derivative liability, noncurrent | (1,191 | ) | — | (1,191 | ) | |||||||
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| |||||||
Total commodity derivative liabilities | $ | (1,538 | ) | $ | 347 | $ | (1,191 | ) | ||||
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NOTE 9. FAIR VALUE MEASUREMENTS
The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, long-term debt, and derivatives. The carrying value of cash and cash equivalents, trade receivables, and trade payables and accrued liabilities are considered to be representative of their fair market value due to the short maturity of these instruments.
The Company’s debt is subject to variable interest rates and accordingly its carrying value is considered to be representative of its fair market value.
F-45
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
The following table provides the carrying value and fair value measurement information for certain of the financial assets and liabilities of the Company (in thousands):
| Fair Value Measurements Using: | ||||||||||||||||||||
| Carrying Amount | Total Fair Value | Level 1 Inputs | Level 2 Inputs | Level 3 Inputs | ||||||||||||||||
June 30, 2024 assets (liabilities): | ||||||||||||||||||||
Commodity derivatives | $ | (7,251 | ) | $ | (7,251 | ) | $ | — | $ | (7,251 | ) | $ | — | |||||||
December 31, 2023 assets (liabilities): | ||||||||||||||||||||
Commodity derivatives | $ | (1,191 | ) | $ | (1,191 | ) | $ | — | $ | (1,191 | ) | $ | — | |||||||
The following methods and assumptions were used to estimate the fair values in the table above.
Level 2 Fair Value Measurements
Commodity derivatives — The fair value of commodity derivatives is estimated using observable market data and assumptions with adjustments based on widely accepted valuation techniques. A discounted cash flow analysis on the expected cash flows of each derivative reflects the contractual terms of the derivative, including period to maturity, and uses observable market-based inputs, including interest rate curves, implied volatilities and credit risk.
Assets Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities of the Company are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets and liabilities.
Asset retirement obligations — The fair value of asset retirement obligations is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation, estimated plugging and abandonment costs, timing of remediation, the credit-adjusted risk-free rate and inflation rate. Significant unobservable inputs (Level 3) utilized in the determination of asset retirement obligations include estimated plugging and abandonment costs of approximately $0.1 million per well, the timing of remediation, which is estimated based on the aggregate average useful life of the Company’s wells, and the credit adjusted risk free rate.
Proved oil and Natural Gas Reserves — The Company’s estimates of proved and proved developed reserves are the major component of its impairment calculations for oil and natural gas properties. The Company reviews and evaluates its oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. If there is an indication the carrying amount of oil and natural gas properties may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax reserve cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The Company’s proved reserves represent the element of these calculations that require various subjective judgments. Estimates of proved reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. These forecasts rely heavily on historical experience of production results, incurred capital costs, operating expenses and workover experience, among other factors. An impairment loss is measured as the amount by which asset carrying value exceeds fair value on an individual field-by-field basis.
F-46
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
NOTE 10. DEBT AND RELATED EXPENSES
The following table presents the outstanding debt and related expenses of the Company (in thousands):
| As of June 30, 2024 | As of December 31, 2023 | |||||||
Fortress Credit Agreement | $ | 57,350 | $ | 58,900 | ||||
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| |||||
Total debt, including current portion | 57,350 | 58,900 | ||||||
Debt issuance costs | (2,540 | ) | (2,935 | ) | ||||
|
|
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| |||||
Total debt, including current portion, net | 54,810 | 55,965 | ||||||
Less: current portion of debt | 6,200 | 6,200 | ||||||
|
|
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| |||||
Long-term debt, net | $ | 48,610 | $ | 49,765 | ||||
|
|
|
| |||||
Debt maturities as of June 30, 2024, including current portion, are as follows (in thousands):
2024 | $ | 3,100 | ||
2025 | 6,200 | |||
2026 | 6,200 | |||
2027 | 41,850 | |||
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| |||
Total | $ | 57,350 | ||
|
|
Fortress Credit Agreement — On January 31, 2023, the Company (“Borrower”) entered into a new Credit and Guaranty Agreement with Fortress Credit Corp. (“Credit Agreement”) with initial loan commitments of $62.0 million provided by Fortress Credit Corp. and Cargill, Incorporated (collectively, the “Lenders”). Upon execution of the Credit Agreement, the Company was issued a new term loan with the Lenders for the full commitment amount of $62.0 million which matures on January 31, 2027 (“Maturity Date”). Proceeds from the new loan were utilized to repay in full the existing Credit Facility and NPA, as well as debt issuance costs. The remaining unused proceeds served as additional cash to the Company’s consolidated balance sheet.
Initially, the obligations under the Credit Agreement are guaranteed by certain of the Borrower’s subsidiaries (the “Guarantors”) and the Credit Agreement is secured by substantially all of the assets owned by the Company and the Guarantors (subject to customary exceptions). Borrowings outstanding under the Credit Agreement will initially be Term SOFR Loans (as defined in the Credit Agreement) which bear interest at a rate equal to the sum of (i) the Term SOFR Rate for a three-month interest period, plus 0.15% (“Adjusted Term SOFR Rate”); and (ii) 8.00% per annum. The Administrative Agent (permitted only as expressly set forth in Section 2.07 of the Credit Agreement), may convert any outstanding Term SOFR Loan to an ABR Loan (as defined in the Credit Agreement). Borrowings constituting ABR Loans shall bear interest at a rate equal to the sum of (i) the Alternate Base Rate, defined as the greater of (a) the Prime Rate and (b) the NYFRB Rate plus 0.50%; and (ii) 7.00% per annum. Interest accrued on all outstanding loans is payable at the end of each quarter, through the Maturity Date.
The Company is required to repay to the Lenders an amount equal to 2.50% of the aggregate principal amount of the outstanding loans, including accrued interest, on the last day of each quarter. Furthermore, the Company is subject to mandatory repayment provisions, including in the event of default where the Lenders elect to accelerate amounts due. The Credit Agreement further outlines the ability to prepay the loans in whole, or in part, at the option of the Company. In the event of any repayment or prepayment of the loans, the Company shall immediately pay the applicable premium (as defined in the Credit Agreement) and all accrued interest.
F-47
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
The Credit Agreement contains restrictive covenants that limit the Company’s ability to, among other things: (i) incur additional indebtedness; (ii) incur liens; (iii) enter into mergers; (iv) dispose of assets; (v) engage in new business type; (vi) make any investments; (vii) enter into certain swap agreements; (viii) make restrictive payments; and (ix) engage in certain transactions with affiliates. These restrictive covenants are subject to a number of important exceptions and qualifications.
In addition, the Credit Agreement requires the Company to maintain compliance with the following financial ratios determined as of the last day of the quarter: (A) a current ratio (as defined in the Credit Agreement) of no less than 1.00 to 1.00; (B) a PDP asset coverage ratio (as defined in the Credit Agreement) of no less than 1.75 to 1.00; (C) a leverage ratio (as defined in the Credit Agreement) of no more than 2.75 to 1.00; and (D) liquidity (as defined in the Credit Agreement) of not less than $5.0 million. Furthermore, for any year, general and administrative expenses (as defined in the Credit Agreement) attributable to the Company must not exceed $8.5 million. The Company was not in compliance with the current ratio as of December 31, 2023. However, on April 11, 2024, the Company received a waiver related to non-compliance with the current ratio. On April 24, 2024, the Company entered into the First Amendment to the Credit Agreement, which moved the payment date for the required quarterly principal and interest payments to the first business day of the immediately succeeding quarter. As of June 30, 2024 the Company was in compliance with all of its financial covenants.
NOTE 11. EQUITYAND SHARE BASED COMPENSATION
Preferred Equity — The Company has issued 958,864 units of preferred shares for cash totaling $95.9 million as of June 30, 2024 and 2023. The Company has not issued any preferred shares since 2018. The preferred shares include the following characteristics and rights:
| • | When declared, the Company shall pay distributions in cash to the holders of the preferred shares in the amount of 6.0% per annum, paid in arrears. |
| • | All or a portion of the preferred shares and accrued but unpaid interest can be converted into common units at a price of $65.00 per unit, or the conversion price then in effect at the time of conversion. |
| • | Each holder of the preferred shares is entitled to one vote per preferred share. |
| • | The preferred shares include a liquidation preference over common units. |
The preferred shares may not demand repayment of the equity or accrued dividends, and if not converted to common units, once the amount of the preferred shares and all accrued dividends has been paid, the holders have no additional rights or claims to the assets of the Company. For the six months ended June 30, 2024 and 2023 no dividends have been declared, therefore, are not recorded on the condensed consolidated balance sheets. The balance of accumulated undeclared distributions totaled $46.8 million as of June 30, 2024 and $43.9 million as of December 31, 2023. The accumulated liquidation preference totaled $142.7 million as of June 30, 2024 and $139.8 million as of December 31, 2023.
Share Based Compensation — The Company has a total of 101,140 options outstanding as of June 30, 2024 and December 31, 2023. The options are exercisable at a price of $100 per option. There were no options granted, forfeited or exercised during the six months ended June 30, 2024 or year ended December 31, 2023. Therefore, the Company had no compensation expense for the six months ended June 30, 2024 and 2023.
The approximate remaining weighted-average contractual term of options outstanding at June 30, 2024 is approximately four years. At June 30, 2024, all options were vested and the Company had no unrecognized share-based compensation expense.
F-48
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
NOTE 12. LEASES
The following table summarizes the operating leases of the Company for the periods indicated (in thousands):
| Six months ended June 30, | ||||||||
| 2024 | 2023 | |||||||
Operating lease expenses | $ | 75 | $ | 77 | ||||
Cash paid for operating lease liabilities | $ | 75 | $ | 77 | ||||
Right-of-use assets obtained in exchange for operating lease liabilities | $ | — | $ | — | ||||
Amortization of right-of-use assets | $ | 76 | $ | 68 | ||||
Lease liability balance | $ | 427 | $ | 560 | ||||
Weighted-average discount rate (%) | 1.37 | 1.37 | ||||||
Weighted-average remaining lease term (years) | 3.0 | 4.0 | ||||||
Total expense for all leases for the six months ended June 30, 2024 and 2023 was $1.0 million and $0.9 million, respectively.
Future minimum annual lease payments as of June 30, 2024 are as follows (in thousands):
2024 | $ | 76 | ||
2025 | 141 | |||
2026 | 131 | |||
2027 | 88 | |||
2028 | — | |||
Thereafter | — | |||
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Total lease payments | 436 | |||
Less: interest | (9 | ) | ||
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Present value of lease liabilities | $ | 427 | ||
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NOTE 13. COMMITMENTS AND CONTINGENCIES
Environmental Matters — Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the operations and the cost of crude oil and natural gas exploration, development, and production operations of the Company. The Company does not anticipate that it will be required in the near future to expend significant amounts for compliance with such federal, state and local laws and regulations, and therefore, no amounts have been accrued for such purposes. At June 30, 2024 and December 31, 2023, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company.
Government Regulation — Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters, including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of June 30, 2024 and December 31, 2023, the Company has not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition, capital expenditures, earnings, or competitive position of the Company in the oil and gas industry.
F-49
PEAK EXPLORATION & PRODUCTION, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 AND 2023
Litigation — The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect any such matters to have a material effect on its financial condition, results of operations or cash flows.
NOTE 14. RELATED PARTY TRANSACTIONS
The Company is subject to an Administrative Service Agreement (“ASA”) with Peak BLM Lease, LLC (“Peak BLM”), an affiliate, that specifies the Company will perform administrative duties associated with Peak BLM’s properties. Per the ASA, Peak BLM is to pay the Company approximately $0.1 million monthly. For the year ended December 31, 2023, Peak BLM prepaid $0.6 million for services to be provided in 2024, and therefore this payment is reflected as a reduction to “general and administrative” on the accompanying unaudited condensed consolidated statements of operations for the six months ended June 30, 2024. For the six months ended June 30, 2023, Peak BLM paid the Company $0.6 million, and these payments are reflected as a reduction to “general and administrative” on the accompanying unaudited condensed consolidated statements of operations. In addition, the Company performs as the administrator of three jointly owned wells for the six months ended June 30, 2024 and one jointly owned well for the six months ended June 30, 2023, which resulted in Peak BLM paying $3.5 million and $0.3 million for six months ended June 30, 2024 and 2023, respectively, for capital expenditures and/or lease operating expenses. There were no other related party balances for the six months ended June 30, 2024, and 2023.
NOTE 15. SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides certain supplemental cash flow information for the periods indicated (in thousands):
| Six Months Ended June 30, | ||||||||
| 2024 | 2023 | |||||||
Supplemental Disclosure of Cash Flow Information: | ||||||||
Cash paid for interest | $ | 1,988 | $ | 4,474 | ||||
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Supplemental Disclosure of Non-Cash Information: | ||||||||
Oil and natural gas additions through accounts payable and accrued expenses | $ | (753 | ) | $ | 1,700 | |||
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Right-of-use asset obtained in exchange for operating lease liabilities | $ | — | $ | — | ||||
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Revisions and additions to asset retirement obligations | $ | — | $ | — | ||||
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NOTE 16. SUBSEQUENT EVENTS
In preparing the accompanying condensed consolidated financial statements of the Company, management has evaluated all subsequent events and transactions for potential recognition or disclosure through the date the condensed consolidated financial statements of the Company were available for issuance. All subsequent events requiring recognition have been incorporated into these condensed consolidated financial statements.
* * * * *
F-50
Report of Independent Registered Public Accounting Firm
To the Board Managers and Member of
Peak BLM Lease LLC and Subsidiary
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Peak BLM Lease LLC and Subsidiary (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, member’s equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2023 and 2022, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Moss Adams LLP
Denver, Colorado
May 29, 2024
We have served as the Company’s auditor since 2017.
F-51
PEAK BLM LEASE LLC AND SUBSIDIARY
(in thousands)
| December 31, | ||||||||
| 2023 | 2022 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 3,677 | $ | 4,621 | ||||
Accounts receivable, net | 690 | 309 | ||||||
Prepaid expenses and other current assets | 610 | 6 | ||||||
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|
| |||||
Total current assets | 4,977 | 4,936 | ||||||
Oil and natural gas property and equipment, based on successful efforts method of accounting, net | 49,883 | 50,372 | ||||||
|
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Total assets | $ | 54,860 | $ | 55,308 | ||||
|
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LIABILITIES AND MEMBER’S EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued expenses | $ | 154 | $ | 812 | ||||
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Total current liabilities | 154 | 812 | ||||||
Other noncurrent liabilities: | ||||||||
Asset retirement obligation | 50 | 46 | ||||||
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Total other noncurrent liabilities | 50 | 46 | ||||||
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Total liabilities | 204 | 858 | ||||||
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Commitments and contingencies | ||||||||
Member’s equity: | ||||||||
Member’s equity | 57,000 | 57,000 | ||||||
Accumulated deficit | (2,344 | ) | (2,550 | ) | ||||
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Total member’s equity | 54,656 | 54,450 | ||||||
|
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Total liabilities and member’s equity | $ | 54,860 | $ | 55,308 | ||||
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F-52
PEAK BLM LEASE LLC AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
REVENUES: | ||||||||
Oil and natural gas sales, net | $ | 4,502 | $ | 10,045 | ||||
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Total revenues, net | 4,502 | 10,045 | ||||||
OPERATING EXPENSES: | ||||||||
Lease operating | 706 | 728 | ||||||
Production and ad valorem taxes | 565 | 1,211 | ||||||
Depletion, depreciation and amortization | 1,740 | 2,230 | ||||||
Accretion | 4 | 4 | ||||||
Abandonment | 50 | 51 | ||||||
General and administrative | 1,264 | 1,303 | ||||||
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Total operating expenses | 4,329 | 5,527 | ||||||
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Income from operations | 173 | 4,518 | ||||||
OTHER INCOME: | ||||||||
Other gain | 33 | 25 | ||||||
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Total other income | 33 | 25 | ||||||
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NET INCOME | $ | 206 | $ | 4,543 | ||||
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F-53
PEAK BLM LEASE LLC AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(in thousands)
| Member’s Equity | Accumulated Deficit | Total | ||||||||||
BALANCE, JANUARY 1, 2022 | $ | 57,000 | $ | (7,093 | ) | $ | 49,907 | |||||
Net income | — | 4,543 | 4,543 | |||||||||
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BALANCE, DECEMBER 31, 2022 | 57,000 | (2,550 | ) | 54,450 | ||||||||
Net income | — | 206 | 206 | |||||||||
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BALANCE, DECEMBER 31, 2023 | $ | 57,000 | $ | (2,344 | ) | $ | 54,656 | |||||
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F-54
PEAK BLM LEASE LLC AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income | $ | 206 | $ | 4,543 | ||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||
Depletion, depreciation and amortization | 1,740 | 2,230 | ||||||
Abandonment | 50 | 51 | ||||||
Accretion expense | 4 | 4 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable, net | (383 | ) | (309 | ) | ||||
Prepaid expenses and other current assets | (601 | ) | (1 | ) | ||||
Accounts payable and accrued expenses | (737 | ) | (2,670 | ) | ||||
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Net cash provided by operating activities | 279 | 3,848 | ||||||
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CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Additions to oil and natural gas properties | (1223 | ) | (4,112 | ) | ||||
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Net cash used in investing activities | (1,223 | ) | (4,112 | ) | ||||
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CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Net cash provided by financing activities | — | — | ||||||
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Net decrease in cash and cash equivalents | (944 | ) | (264 | ) | ||||
Cash and cash equivalents at beginning of year | 4,621 | 4,885 | ||||||
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Cash and cash equivalents at end of year | $ | 3,677 | $ | 4,621 | ||||
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SUPPLEMENTAL STATEMENT OF CASH FLOW DISCLOSURES: | ||||||||
Oil and gas additions through accounts payable and accrued expenses | $ | 78 | $ | 121 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-55
PEAK BLM LEASE LLC AND SUBSIDIARY
NOTES TO CONSOLIDATED STATEMENTS
DECEMBER 31, 2023 AND 2022
NOTE 1. ORGANIZATIONAND SIGNIFICANT ACCOUNTING POLICIES
Description of the Business — The accompanying consolidated financial statements include the accounts of Peak BLM Lease LLC (“Peak BLM”) and Peak Powder River Acquisitions, LLC (“PPRA”, collectively, the “Company”). The Company is an independent oil and natural gas company engaged in exploration and development of crude oil and natural gas assets. The Company, at this time, conducts its activities in Wyoming. As a Limited Liability Company (“LLC”), the amount of loss at risk for its sole member is limited to the amount of capital contributed to the LLC, and unless otherwise noted, the sole Member’s liability for indebtedness of an LLC is limited to the Member’s actual capital contribution. The Company will have LLC status until perpetual existence unless it is terminated.
Basis of Presentation — The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and include the accounts of Peak BLM and PPRA. All intercompany accounts and transactions have been eliminated.
Use of Estimates — The preparation of consolidated financial statements in accordance with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ significantly from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include timing and costs associated with asset retirement obligations, and oil and gas reserve quantities, which are the basis for the calculation of depreciation, depletion and impairment of oil and natural gas properties.
Cash and Cash Equivalents — Cash and cash equivalents consist of highly liquid investments, with original maturities of three months or less.
Concentrations of Credit Risk — The Company regularly has cash in financial institutions which, at times, may exceed depository insurance limits. The Company places such deposits with high credit quality institutions and has not experienced any credit losses. Substantially all of the Company’s receivables are within the oil and gas industry, primarily from its oil and gas purchasers and joint interest owners. Although diversified within several companies, collectability is largely dependent upon the general economic conditions of the industry.
Accounts Receivable – Oil and Gas Sales — The Company accrues for oil and natural gas sales based on actual production dates. These are due within 45 days of production. The Company determines its allowance for each type of receivable based on the length of time the receivable is past due, its previous loss history, and customers current ability to pay its obligation. The Company also bases its allowance for each type of receivable on its respective credit risks. The Company writes off specific receivables when they become uncollectible. Once an allowance is recorded, any subsequent payments received on such receivables are credited to the allowance for credit losses. To date, the Company has not experienced any pattern of credit losses and therefore has no allowance as of December 31, 2023 and 2022. The Company will continually monitor the creditworthiness of its counterparties by reviewing credit ratings, financial statements, and payment history. Accounts receivable from oil and gas sales for the years ended December 31, 2023 and 2022 were $0.7 million and $0.3 million, respectively. As of January 1, 2022, there were no accounts receivable for oil and gas sales.
Accounting for Oil and Natural Gas Properties — The Company utilizes the successful efforts method of accounting for its oil and gas properties. Leasehold costs, tangible and intangible costs of development wells, and costs of successful exploration wells, are capitalized as incurred. Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If
F-56
proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Costs of unsuccessful exploration efforts are expensed in the period it is determined that proved reserves were not found and such costs are not recoverable through future revenues. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of development wells are capitalized whether productive or nonproductive. Upon the sale of proved properties, the cost and accumulated depletion are removed from the accounts and any gain or loss is charged to income.
Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one barrel of oil. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the depletion rate (amortizable base divided by beginning of period proved reserves) to current period production.
The Company reviews and evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax reserve cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. An impairment loss is measured as the amount by which asset carrying value exceeds fair value on an individual field-by-field basis.
The Company also performs a review of unproved property costs to determine (i) whether any leases associated with the property have expired or been abandoned, (ii) whether the subject property will be developed or (iii) if the carrying value of the property is not realizable.
Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s depletion rate. These gains and losses are classified as asset dispositions in the consolidated statements of operations. Partial common operating field sales or dispositions deemed not to significantly alter the depletion rate are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.
Revenue Recognition — Revenue from the sale of oil and natural gas are recognized, as the product is delivered to the customers’ custody transfer points and collectability is reasonably assured. The Company fulfills the performance obligations under the customer contracts through daily delivery of oil and natural gas to the customers’ custody transfer points. Revenues are recorded on a monthly basis using the prices received under the Company’s contracts. These contracts are generally derived from stated market prices which are adjusted to reflect deductions, including transportation, fractionation and processing. As a result, the revenues from the sale of oil and natural gas are subject to change with the increase or decrease in market prices. The sales of oil and natural gas, as presented on the consolidated statements of operations, represent the Company’s share of revenues, net of royalties and excluding revenue interests owned by others.
F-57
When selling oil and natural gas on behalf of royalty owners or working interest owners, the Company acts as an agent and therefore reports the revenue on a net share basis. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Historically, differences between revenue estimates and actual revenue received have not been significant.
The majority of product sale commitments of the Company are short-term in nature with a contractual term of one year or less. For these contracts, the Company applies the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14, which exempts entities from disclosing the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.
For contracts with terms greater than one-year, the Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in ASC 606-10-50-14A, which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
Income Taxes — The Company is an LLC classified as an entity disregarded as separate from its sole member for U.S. federal income tax purposes. Accordingly, no provision for income tax has been recorded as the income, deductions, expenses, and credits of the Company are reported on the income tax returns of the Company’s sole member.
Under professional standards, the Company’s policy is to evaluate the likelihood that its uncertain tax positions will prevail upon examination based on the extent to which those positions have substantial support within the Internal Revenue Code and Regulations, revenue rulings, court decisions, and other evidence.
The federal income tax returns of the Company are subject to examination by the Internal Revenue Service, generally for three years after they were filed. The Company expects no material changes to its unrecognized tax positions within the next 12 months.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2023 and 2022, no interest and penalties related to uncertain tax positions were accrued.
Fair Value of Financial Instruments — The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, and accrued liabilities. The carrying value of cash and cash equivalents, trade receivables, trade payables and accrued liabilities are considered to be representative of their fair market value due to the short maturity of these instruments.
Because considerable judgment may be required to develop estimates of fair value, the estimates provided may not be indicative of the amounts the Company could realize upon the sale or refinancing of financial instruments.
Asset Retirement Obligation — The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The Company depletes the amount added to proved oil and natural gas property costs and recognizes accretion expense in connection with the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate
F-58
estimated at the time the liability is incurred or revised. Revisions to the liability are due to increases in estimated abandonment costs and changes in well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.
Leases — The Company records a right-of-use asset and a lease liability on the consolidated balance sheets for all leases with terms longer than 12 months. Leases are classified as either finance or operating, with classification affecting the pattern of expense recognition on the statement of operations.
The Company previously elected certain practical expedients and accordingly has (1) carried forward its prior assessments of (a) whether existing contracts on the January 1, 2022, adoption date contain leases, (b) classification of leases as operating or financing, and (c) initial direct costs for existing leases and (2) considered hindsight in determining the lease term and assessing impairment of the right-of-use-asset. The Company previously elected the land easement practical expedient, where the Company need not reassess whether any existing or expired land easements under the previous guidance are leases or contain a lease under the new guidance. Additionally, the Company has previously elected not to account for lease components separately from the non-lease components. The Company has no lease contracts requiring recognition in the consolidated financial statements for the years December 31, 2023 and 2022.
Commitments and Contingencies — Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.
Segments — The crude oil and natural gas and production activities of the Company are solely focused in the United States. The Company has one operating segment and therefore one reporting segment, exploration and production.
Recent Accounting Pronouncements — In June 2016, the Financial Accounting Standard Board issued Accounting Standards Update 2016-13, “Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“ASU 2016-13”). ASU 2016-13 requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. ASU 2016-13 is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. In November 2019, the FASB ASU 2019-19, “Codification Improvements to Topic 326: Financial Instruments — Credit Losses”, which makes amendments to clarify the scope of the guidance, including clarification that receivables arising from operating leases are not within its scope. The amended guidance was effective for the Company on January 1, 2023 and did not result in a material impact to the financial position, cash flows, or results of operations.
NOTE 2. OILAND NATURAL GAS PROPERTIES
The following table reflects the aggregate capitalized costs associated with the Company (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Oil and natural gas properties: | ||||||||
Unproved properties | $ | 41,139 | $ | 41,123 | ||||
Proved properties | 13,095 | 10,564 | ||||||
Work in process | 88 | 1,384 | ||||||
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Total oil and natural gas properties | 54,322 | 53,071 | ||||||
Less: Accumulated depreciation, depletion and amortization | (4,439 | ) | (2,699 | ) | ||||
|
|
|
| |||||
Oil and natural gas properties, net | $ | 49,883 | $ | 50,372 | ||||
|
|
|
| |||||
F-59
Depletion expense was $1.7 million and $2.2 million for the years ended December 31, 2023 and 2022, respectively. Certain leases associated with unproved property were allowed to expire, resulting in abandonment expenses of $0.1 million for each of the years ended December 31, 2023 and 2022. For the years ended December 31, 2023 and 2022, there was no impairment expense associated with the Company’s proved properties. The Company had no exploratory wells costs during the years ended December 31, 2023 and 2022.
NOTE 3. REVENUE
The following table presents the disaggregation of oil and natural gas revenue of the Company (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Oil sales | $ | 3,964 | $ | 9,204 | ||||
Natural gas sales | 538 | 841 | ||||||
|
|
|
| |||||
Total oil and natural gas sales, net | $ | 4,502 | $ | 10,045 | ||||
|
|
|
| |||||
NOTE 4. ASSET RETIREMENT OBLIGATIONS
The following table presents changes in asset retirement obligations of the Company (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Asset retirement obligations at beginning of period | $ | 46 | $ | 11 | ||||
Liabilities incurred | — | 31 | ||||||
Liabilities settled and divested | — | — | ||||||
Revision of estimated obligation | — | — | ||||||
Accretion expense on discounted obligation | 4 | 4 | ||||||
|
|
|
| |||||
Asset retirement obligations at end of period | $ | 50 | $ | 46 | ||||
|
|
|
| |||||
NOTE 5. COMMITMENTS AND CONTINGENCIES
Environmental Matters — Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the operations and the cost of crude oil and natural gas exploration, development, and production operations of the Company. The Company does not anticipate that it will be required in the near future to expend significant amounts for compliance with such federal, state and local laws and regulations, and therefore, no amounts have been accrued for such purposes. At December 31, 2023 and 2022, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company.
Government Regulation — Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters, including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2023 and 2022, the Company has not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition, capital expenditures, earnings, or competitive position of the Company in the oil and gas industry.
Litigation — The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory
F-60
compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect any such matters to have a material effect on its financial condition, results of operations or cash flows.
NOTE 6. RELATED PARTY TRANSACTIONS
The Company is subject to an Administrative Service Agreement (“ASA”) with Peak Exploration and Production, LLC (“Peak E&P”), an affiliate, that specifies that Peak E&P will perform administrative duties associated with the Company’s properties. Per the ASA, the Company is to pay Peak E&P approximately $0.1 million monthly. For the years ended December 31, 2023, and 2022, the Company paid Peak E&P $1.8 million and $1.2 million, respectively, and are generally reflected within “general and administrative” on the accompany consolidated statements of operations. For the year ended December 31, 2023, $0.6 million of amounts paid to Peak E&P were for services to be provided in 2024, and is therefore included within “prepaid expenses and other current assets” on the consolidated balance sheet at December 31, 2023. In addition, Peak E&P performs as the administrator of one jointly owned well, which resulted in the Company paying $0.4 million and $5.0 million for the years ended December 31, 2023 and 2022, respectively for capital expenditures and/or lease operating expenses. There were no other related party transactions for the years ended December 31, 2023, and 2022.
NOTE 7. SUBSEQUENT EVENTS
In preparing the accompanying consolidated financial statements of the Company, management has evaluated all subsequent events and transactions for potential recognition or disclosure through the date the consolidated financial statements of the Company were available for issuance. All subsequent events requiring recognition have been incorporated into these consolidated financial statements.
F-61
PEAK BLM LEASE LLC AND SUBSIDIARY
SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)
DECEMBER 31, 2023 AND 2022
NOTE 8. SUPPLEMENTAL OILAND NATURAL GAS INFORMATION (UNAUDITED)
Supplemental unaudited information regarding the Company’s oil and natural gas activities is presented in this note. All of the Company’s oil and natural gas reserves are located in the U.S.
Costs Incurred — The following table reflects the costs incurred in oil and natural gas property acquisition, exploration, and development activities (in thousands):
| For the Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Property acquisition costs: | ||||||||
Proved properties | $ | — | $ | — | ||||
Unproved properties | — | — | ||||||
Exploration costs | — | — | ||||||
Development costs | 1,251 | 4,112 | ||||||
|
|
|
| |||||
Costs incurred | $ | 1,251 | $ | 4,112 | ||||
|
|
|
| |||||
Results of Operations — The following table includes revenues and expenses associated with the Company’s oil and natural gas producing activities (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Oil and natural gas sales, net | $ | 4,502 | $ | 10,045 | ||||
Lease operating | (706 | ) | (728 | ) | ||||
Depletion, depreciation and amortization expense | (1,740 | ) | (2,230 | ) | ||||
Accretion | (4 | ) | (4 | ) | ||||
Abandonment | (50 | ) | (51 | ) | ||||
|
|
|
| |||||
Results of operations | $ | 2,002 | $ | 7,032 | ||||
|
|
|
| |||||
Estimated Quantities of Proved Oil and Natural Gas Reserves — Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with the changes in prices and operating costs. Reserve estimates are inherently imprecise and those estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
F-62
A summary of the Company’s change in quantities of proved oil and natural gas reserves for the years ended December 31, 2023 and 2022 are as follows:
| Year ended December 31, 2023 | ||||||||||||||||
| Oil (Bbl) | Natural Gas (Mcf) | Liquids* (Bbl) | Total Boe | |||||||||||||
Proved reserves as of December 31, 2022 | 481,230 | 1,303,376 | — | 698,459 | ||||||||||||
Revisions of previous estimates | (176,596 | ) | (635,200 | ) | — | (282,463 | ) | |||||||||
Extensions, discoveries and other additions | 22,359 | 505,142 | — | 106,549 | ||||||||||||
Production | (53,094 | ) | (220,736 | ) | — | (89,883 | ) | |||||||||
Purchases (sales) of minerals in place | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Proved reserves as of December 31, 2023 | 273,899 | 952,582 | — | 432,662 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Proved developed reserves | ||||||||||||||||
Beginning of year | 341,342 | 795,593 | — | 473,941 | ||||||||||||
End of year | 273,899 | 952,582 | — | 432,662 | ||||||||||||
Proved undeveloped reserves | ||||||||||||||||
Beginning of year | 139,888 | 507,783 | — | 224,518 | ||||||||||||
End of year | — | — | — | — | ||||||||||||
| Year ended December 31, 2022 | ||||||||||||||||
| Oil (Bbl) | Natural Gas (Mcf) | Liquids* (Bbl) | Total Boe | |||||||||||||
Proved reserves as of December 31, 2021 | 170,844 | 581,848 | — | 267,819 | ||||||||||||
Revisions of previous estimates | 85,573 | 73,430 | — | 97,811 | ||||||||||||
Extensions, discoveries and other additions | 323,311 | 748,224 | — | 448,015 | ||||||||||||
Production | (98,498 | ) | (100,126 | ) | — | (115,186 | ) | |||||||||
Purchases (sales) of minerals in place | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Proved reserves as of December 31, 2022 | 481,230 | 1,303,376 | — | 698,459 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Proved developed reserves | ||||||||||||||||
Beginning of year | 34,217 | 89,788 | — | 49,182 | ||||||||||||
End of year | 341,342 | 795,593 | — | 473,941 | ||||||||||||
Proved undeveloped reserves | ||||||||||||||||
Beginning of year | 136,627 | 492,060 | — | 218,637 | ||||||||||||
End of year | 139,888 | 507,783 | — | 224,518 | ||||||||||||
| * | The Company has not historically separately reported reserve quantities for liquids |
For the year ended December 31, 2023, extensions, discoveries and other additions resulted from three new wells drilled for 106,549 Boe. Revisions for the year ended December 31, 2023 were largely driven by lower commodity prices during the year. Lower commodity prices decrease the overall value of reserves along with the amount of economically recoverable reserves quantities.
For the year ended December 31, 2022, extensions, discoveries and other additions resulted from two new wells drilled for 448,015 Boe. Revisions for the year ended December 31, 2022 were largely driven by higher commodity prices during the year. Higher commodity prices increase the overall value of reserves along with the amount of economically recoverable reserves quantities.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions.
F-63
Proved reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”), which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first day of the month spot prices prior to the end of the reporting period. These SEC prices as of December 31, 2023 and 2022 were $78.22 and $93.67 per barrel of oil and $2.64 and $6.36 per MMBtu of natural gas, respectively.
The estimated realized prices used in computing the Company’s reserves as of December 31, 2023 were as follows: (i) $76.75 per barrel of oil, and (ii) $2.66 per Mcf of natural gas. The estimated realized prices used in computing the Company’s reserves as of December 31, 2022 were as follows: (i) $91.93 per barrel of oil, and (ii) $6.67 per Mcf of natural gas.
All realized prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the “as of date” forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses would have been computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the oil and natural gas properties of the Company. The estimated future net cash flows are then discounted at a rate of 10.0%.
The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods presented (in thousands):
| December 31, | ||||||||
| 2023 | 2022 | |||||||
Future cash inflows | $ | 23,553 | $ | 52,993 | ||||
Future production costs | (12,082 | ) | (20,073 | ) | ||||
Future development and abandonment costs | (90 | ) | (3,124 | ) | ||||
Future income taxes | — | — | ||||||
|
|
|
| |||||
Future net cash flows | 11,381 | 29,796 | ||||||
10% annual discount for estimated timing of cash flows | (3,909 | ) | (12,719 | ) | ||||
|
|
|
| |||||
Standardized measure of discounted future net cash flows | $ | 7,472 | $ | 17,077 | ||||
|
|
|
| |||||
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the proved reserves of the Company. The disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10.0% discount rate is set by regulators. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
F-64
The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods presented (in thousands):
| Year Ended December 31, | ||||||||
| 2023 | 2022 | |||||||
Standardized measure of discounted future net cash flows at January 1 | $ | 17,077 | $ | 3,733 | ||||
Net change in prices and production costs | (3,454 | ) | 5,073 | |||||
Changes in estimated future development and abandonment costs | — | (376 | ) | |||||
Sales of crude oil and natural gas produced, net of production costs | (3,243 | ) | (8,106 | ) | ||||
Extensions, discoveries and improved recoveries, less related costs | 1,134 | 12,153 | ||||||
Purchases (sales) of minerals in place, net | — | — | ||||||
Revisions of previous quantity estimates | (5,754 | ) | 2,933 | |||||
Development costs incurred during the period | 495 | — | ||||||
Change in income taxes | — | — | ||||||
Accretion of discount | 1,708 | 373 | ||||||
Change in timing of estimated future production and other | (491 | ) | 1,294 | |||||
|
|
|
| |||||
Net change | (9,605 | ) | 13,344 | |||||
|
|
|
| |||||
Standardized measure of discounted future net cash flows at December 31 | $ | 7,472 | $ | 17,077 | ||||
|
|
|
| |||||
Estimates of economically recoverable oil and natural gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.
* * * * *
F-65
PEAK BLM LEASE LLC AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands)
| June 30, 2024 | December 31, 2023 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,071 | $ | 3,677 | ||||
Accounts receivable, net | 448 | 690 | ||||||
Prepaid expenses and other current assets | 190 | 610 | ||||||
|
|
|
| |||||
Total current assets | 1,709 | 4,977 | ||||||
Oil and natural gas property and equipment, based on successful efforts method of accounting, net | 52,671 | 49,883 | ||||||
|
|
|
| |||||
Total assets | $ | 54,380 | $ | 54,860 | ||||
|
|
|
| |||||
LIABILITIES AND MEMBER’S EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued expenses | $ | 180 | $ | 154 | ||||
|
|
|
| |||||
Total current liabilities | 180 | 154 | ||||||
Other noncurrent liabilities: | ||||||||
Asset retirement obligation | 52 | 50 | ||||||
|
|
|
| |||||
Total other noncurrent liabilities | 52 | 50 | ||||||
|
|
|
| |||||
Total liabilities | 232 | 204 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Member’s equity: | ||||||||
Member’s equity | 57,000 | 57,000 | ||||||
Accumulated deficit | (2,852 | ) | (2,344 | ) | ||||
|
|
|
| |||||
Total member’s equity | 54,148 | 54,656 | ||||||
|
|
|
| |||||
Total liabilities and member’s equity | $ | 54,380 | $ | 54,860 | ||||
|
|
|
| |||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-66
PEAK BLM LEASE LLC AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands)
| Six Months Ended June 30, | ||||||||
| 2024 | 2023 | |||||||
REVENUES: | ||||||||
Oil and natural gas sales, net | $ | 1,552 | $ | 2,695 | ||||
|
|
|
| |||||
Total revenues, net | ||||||||
OPERATING EXPENSES: | ||||||||
Lease operating | 347 | 333 | ||||||
Production and ad valorem taxes | 209 | 365 | ||||||
Depletion, depreciation and amortization | 608 | 1,136 | ||||||
Accretion | 2 | 2 | ||||||
Abandonment | 52 | 33 | ||||||
General and administrative | 880 | 634 | ||||||
|
|
|
| |||||
Total operating expenses | 2,098 | 2,503 | ||||||
|
|
|
| |||||
Income (loss) from operations | (546 | ) | 192 | |||||
OTHER INCOME: | ||||||||
Other gain | 38 | — | ||||||
|
|
|
| |||||
Total other income | 38 | — | ||||||
|
|
|
| |||||
NET INCOME (LOSS) | $ | (508 | ) | $ | 192 | |||
|
|
|
| |||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-67
PEAK BLM LEASE LLC AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY (UNAUDITED)
(in thousands)
| Member’s Equity | Accumulated Deficit | Total | ||||||||||
BALANCE, JANUARY 1, 2024 | $ | 57,000 | $ | (2,344 | ) | $ | 54,656 | |||||
Net loss | — | (508 | ) | (508 | ) | |||||||
|
|
|
|
|
| |||||||
BALANCE, JUNE 30, 2024 | $ | 57,000 | $ | (2,852 | ) | $ | 54,148 | |||||
|
|
|
|
|
| |||||||
| Member’s Equity | Accumulated Deficit | Total | ||||||||||
BALANCE, JANUARY 1, 2023 | $ | 57,000 | $ | (2,550 | ) | $ | 54,450 | |||||
Net income | — | 192 | 192 | |||||||||
|
|
|
|
|
| |||||||
BALANCE, JUNE 30, 2023 | $ | 57,000 | $ | 2,358 | $ | 54,642 | ||||||
|
|
|
|
|
| |||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-68
PEAK BLM LEASE LLC AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
| Six Months Ended June 30, | ||||||||
| 2024 | 2023 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income (loss) | $ | (508 | ) | 192 | ||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | ||||||||
Depletion, depreciation and amortization | 608 | 1,136 | ||||||
Abandonment | 52 | 33 | ||||||
Accretion expense | 2 | 2 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable, net | 242 | (787 | ) | |||||
Prepaid expenses and other current assets | 420 | (23 | ) | |||||
Accounts payable and accrued expenses | 3 | (769 | ) | |||||
|
|
|
| |||||
Net cash provided by (used in) operating activities | 819 | (216 | ) | |||||
|
|
|
| |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Additions to oil and natural gas properties | (3,425 | ) | (1,198 | ) | ||||
|
|
|
| |||||
Net cash used in investing activities | (3,425 | ) | (1,198 | ) | ||||
|
|
|
| |||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Net cash provided by financing activities | — | — | ||||||
|
|
|
| |||||
Net decrease in cash and cash equivalents | (2,606 | ) | (1,414 | ) | ||||
Cash and cash equivalents at beginning of period | 3,677 | 4,621 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 1,071 | 3,207 | |||||
|
|
|
| |||||
SUPPLEMENTAL STATEMENT OF CASH FLOW DISCLOSURES: | ||||||||
Oil and gas additions through accounts payable and accrued expenses | $ | 23 | 78 | |||||
|
|
|
| |||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-69
PEAK BLM LEASE LLC AND SUBSIDIARY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2024 and 2023
NOTE 1. ORGANIZATIONAND SIGNIFICANT ACCOUNTING POLICIES
Description of the Business — The accompanying condensed consolidated financial statements include the accounts of Peak BLM Lease LLC (“Peak BLM”) and Peak Powder River Acquisitions, LLC (“PPRA”, collectively, the “Company”). The Company is an independent oil and natural gas company engaged in exploration and development of crude oil and natural gas assets. The Company, at this time, conducts its activities in Wyoming. As a Limited Liability Company (“LLC”), the amount of loss at risk for each individual member is limited to the amount of capital contributed to the LLC, and unless otherwise noted, the sole Member’s liability for indebtedness of an LLC is limited to the Member’s actual capital contribution. The Company will have LLC status until perpetual existence unless it is terminated.
Basis of Presentation — The unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and include the accounts of Peak BLM and PPRA. All intercompany accounts and transactions have been eliminated. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2023. Results for the interim periods are not necessarily indicative of results to be expected for the full year ended December 31, 2024. In the opinion of management, these condensed consolidated financial statements reflect all normal recurring adjustments necessary for a fair presentation of the result for the periods indicated.
Use of Estimates — The preparation of the condensed consolidated financial statements in accordance with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ significantly from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include timing and costs associated with asset retirement obligations, and oil and gas reserve quantities, which are the basis for the calculation of depreciation, depletion and impairment of oil and natural gas properties.
NOTE 2. OILAND NATURAL GAS PROPERTIES
The following table reflects the aggregate capitalized costs associated with the Company (in thousands):
| As of June 30, 2024 | As of December 31, 2023 | |||||||
Oil and natural gas properties: | ||||||||
Unproved properties | $ | 41,232 | $ | 41,139 | ||||
Proved properties, net of impairment | 13,099 | 13,095 | ||||||
Work in process, net of impairment | 3,370 | 75 | ||||||
|
|
|
| |||||
Total oil and natural gas properties | 57,701 | 54,309 | ||||||
Less: Accumulated depreciation, depletion and amortization | (5,030 | ) | (4,426 | ) | ||||
|
|
|
| |||||
Oil and natural gas properties, net | $ | 52,671 | $ | 49,883 | ||||
|
|
|
| |||||
F-70
PEAK BLM LEASE LLC AND SUBSIDIARY
NOTES TO CONDENSED CONSOLIDATED STATEMENTS
JUNE 30, 2024 AND 2023
Depletion expense was $0.6 million and $1.1 million for the six months ended June 30, 2024 and 2023, respectively. There were no impairments of oil and natural gas properties for the six months ended June 30, 2024 and 2023.
NOTE 3. REVENUE
The following table presents the disaggregation of oil and natural gas revenue of the Company (in thousands):
| Six Months Ended June 30, | ||||||||
| 2024 | 2023 | |||||||
Oil sales | $ | 1,410 | $ | 2,325 | ||||
Natural gas sales | 142 | 370 | ||||||
|
|
|
| |||||
Total oil and natural gas sales, net | $ | 1,552 | $ | 2,695 | ||||
|
|
|
| |||||
NOTE 4. ASSET RETIREMENT OBLIGATIONS
The following table presents changes in asset retirement obligations of the Company (in thousands):
| As of June 30, 2024 | As of December 31, 2023 | |||||||
Asset retirement obligations at beginning of period | $ | 50 | $ | 46 | ||||
Liabilities incurred | — | — | ||||||
Liabilities settled and divested | — | — | ||||||
Revision of estimated obligation | — | — | ||||||
Accretion expense on discounted obligation | 2 | 4 | ||||||
|
|
|
| |||||
Asset retirement obligations at end of period | $ | 52 | $ | 50 | ||||
|
|
|
| |||||
NOTE 5. COMMITMENTS AND CONTINGENCIES
Environmental Matters — Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the operations and the cost of crude oil and natural gas exploration, development, and production operations of the Company. The Company does not anticipate that it will be required in the near future to expend significant amounts for compliance with such federal, state and local laws and regulations, and therefore, no amounts have been accrued for such purposes. At June 30, 2024 and December 31, 2023, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company.
Government Regulation — Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters, including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of June 30, 2024 and December 31, 2023, the Company has not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition, capital expenditures, earnings, or competitive position of the Company in the oil and gas industry.
F-71
PEAK BLM LEASE LLC AND SUBSIDIARY
NOTES TO CONDENSED CONSOLIDATED STATEMENTS
JUNE 30, 2024 AND 2023
Litigation — The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect any such matters to have a material effect on its financial condition, results of operations or cash flows.
NOTE 6. RELATED PARTY TRANSACTIONS
The Company is subject to an Administrative Service Agreement (“ASA”) with Peak Exploration and Production, LLC (“Peak E&P”), an affiliate, that specifies that Peak E&P will perform administrative duties associated with the Company’s properties. Per the ASA, the Company is to pay Peak E&P approximately $0.1 million monthly. For the year ended December 31, 2023, the Company prepaid $0.6 million for services to be provided in 2024, and therefore this payment is reflected in “general and administrative” on the accompanying unaudited condensed consolidated statements of operations for the six months ended June 30, 2024. For the six months ended June 30, 2023, Peak BLM paid the Company $0.6 million, and these payments are reflected as a reduction to “general and administrative” on the accompanying unaudited condensed consolidated statements of operations. In addition, Peak E&P performs as the administrator of three jointly owned wells for the six months ended June 30, 2024 and one jointly owned well for the six months ended June 30, 2023, which resulted in the Company paying $3.5 million and $0.3 million for the six months ended June 30, 2024 and 2023, respectively, for capital expenditures and/or lease operating expenses. There were no other related party transactions for the six months ended June 30, 2024, and 2023.
NOTE 7. SUBSEQUENT EVENTS
In preparing the accompanying condensed consolidated financial statements of the Company, management has evaluated all subsequent events and transactions for potential recognition or disclosure through the date the condensed consolidated financial statements of the Company were available for issuance. All subsequent events requiring recognition have been incorporated into these condensed consolidated financial statements.
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GLOSSARY OF OIL AND GAS TERMS
The terms and abbreviations defined in this section are used throughout this prospectus:
“AFE.” Authorization for expenditure.
“APD.” Application for permit to drill.
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGL.
“Bbl/d.” Bbl per day.
“Boe.” One barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to one Bbl of oil.
“Boe/d.” Boe per day.
“Btu.” One British thermal unit — a measure of the amount of energy required to raise the temperature of a one pound mass of water one degree Fahrenheit at sea level.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Condensate.” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Differential.” An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“DSU.” Drilling and Spacing Unit.
“Economically producible.” As it relates to a resource, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).
“Exploratory well.” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a
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development well, an extension well, a service well, or a stratigraphic test well as those items are defined under Regulation S-X.
“Estimated ultimate recovery” or “EUR.” The sum of reserves remaining as of a given date and cumulative production as of that date.
“Field.” An area consisting of a single reservoir or multiple reservoirs, all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).
“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
“Fracturing” or “fracture stimulation.” The process of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this process, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
“Gas” or “Natural gas.” The lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.
“GOR.” Gas to oil ratio.
“Gross acres” or “gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Held by production.” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
“Hydraulic fracturing.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
“Injection Wells.” A well in which fluids are injected rather than produced, the primary objective typically being to maintain reservoir pressure.
“Leases.” Full or partial interests in oil or natural gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.
“Lease operating expense.” The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
“MBbl.” One thousand barrels of crude oil, condensate or NGLs.
“Mboe.” One thousand Boe.
“MBoe/d.” One thousand Boe per day.
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“MMBoe.” One million Boe.
“Mcf.” One thousand cubic feet of natural gas.
“Mineral Interest.” A perpetual right to exploit, mine and produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to a working interest holder pursuant to an oil and natural gas lease.
“MMBtu.” One million Btu.
“MMcf.” One million cubic feet of natural gas.
“MMcf/d.” One million cubic feet of natural gas per day.
“Natural Gas Liquids” (“NGLs”). Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
“Net acres” or “net wells.” The percentage of total acres or wells an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
“Net revenue interest.” (i) In respect of our leasehold acreage, all of the working interests less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas and (ii) in respect of our mineral acreage, all retained royalties plus any working interest in such acreage, less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.
“NYMEX.” The New York Mercantile Exchange.
“Offset operator.” Any entity that has an active lease on an adjoining property for oil, natural gas or NGLs purposes.
“OPEC.” Organization of the Petroleum Exporting Countries.
“Operator.” The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.
“Overriding royalty interest.” An interest in the gross revenues or production over and above the landowner’s royalty carved out of the working interest in a lease and also unencumbered with any expenses of operation, development or maintenance; provided, however it shall bear its proportionate share of transporting, marketing, separating, processing and treating costs and its proportionate share of production, severance, excise, ad valorem and other taxes.
“PCAOB.” The Public Company Accounting Oversight Board.
“PDP.” Proved developed producing.
“Play.” A geographic area with hydrocarbon potential.
“Possible reserves.” Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed
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the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
“Probable reserves.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“Productive well.” A well that is found to be producing, or mechanically capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Proppant.” Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.
“Prospect.” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
“Proved area.” Part of a property to which proved reserves have been specifically attributed.
“Proved developed reserves.” Reserves that can be expected to be recovered through (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“Proved reserves.” Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs, and under existing economic conditions,
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operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).
“Proved undeveloped reserves” (“PUD reserves”). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years unless specific circumstances justify a longer time.
“PV-10.” When used with respect to oil and natural gas reserves, PV-10 represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. Calculation of PV-10 does not give effect to derivatives transactions. Our PV-10 has historically been computed on the same basis as our Standardized Measure, the most comparable measure under GAAP. PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Royalty.” The share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
“Royalty interest.” An interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.
“SCF.” A measure of natural gas at standard conditions, normally 60 degF and 14.7 psia representing 1 cubic foot.
“SEC Pricing.” The oil and gas price parameters established by the current SEC guidelines, including the use of an average effective price, calculated as prices equal to the 12-month unweighted arithmetic average of the first day of the month prices for each of the preceding 12 months as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.
“Section.” 640 acres.
“Seismic Data.” An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40 acre spacing, and is often established by regulatory agencies.
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“Standardized Measure.” Standardized Measure is our standardized measure of discounted future net cash flows, which is prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. No provision is included for federal income taxes since our future net cash flows are not subject to taxation. However, our operations are subject to the Texas franchise tax. Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as effected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.
“STB.” A measure of the volume of treated oil stored in stock tanks representing 42 U.S. gallons.
“TOC.” Total organic carbon.
“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.
“unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Unproved properties.” Properties with no proved reserves.
“Wellbore.” The hole drilled by the bit that is equipped for oil and natural gas production on a completed well. Also called well or borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil and natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“Workover.” Operations on a producing well to restore or increase production.
“WTI.” West Texas Intermediate.
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Peak Resources LP
Class A Common Units
PROSPECTUS
Lead Book-Running Manager
Janney Montgomery Scott
Joint Book-Running Managers
Roth Capital Partners | Texas Capital Securities |
Co-Manager
Seaport Global
, 2024
Until , 2024 (25 days after the date of this prospectus), all dealers that buy, sell or trade our ordinary Class A Common Units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to its unsold allotments or subscriptions.
PART II
Information Not Required in Prospectus
| Item 13. | Other Expenses of Issuance and Distribution. |
The following table sets forth the estimated fees and expenses paid or payable by us in connection with the issuance and distribution of securities in this offering. All amounts are estimates except for the SEC registration, Financial Industry Regulatory Authority, Inc. filing and stock exchange listing fees.
SEC registration fee | $ | 12,731 | ||
FINRA filing fee | * | |||
NYSE American listing fee | * | |||
Accounting fees and expenses | * | |||
Legal fees and expenses | * | |||
Engineering Expenses | * | |||
Printing and engraving expenses | * | |||
Transfer agent and registrar fees and expenses | * | |||
Miscellaneous expenses | * | |||
|
| |||
Total | $ | * | ||
|
|
| * | To be provided by amendment. |
| Item 14. | Indemnification of Directors and Officers. |
Peak Resources LP
Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against any and all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by law against all losses, claims, damages or similar events, unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the applicable person acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal, and is incorporated herein by this reference.
The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for the indemnification of Peak Resources LP and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.
Peak Resources GP LLC
Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.
Under the amended and restated limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses),
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judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):
| • | any person who is or was an affiliate of our general partner (other than us and our subsidiaries); |
| • | any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner; |
| • | any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and |
| • | any person designated by our general partner. |
Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.
| Item 15. | Recent Sales of Unregistered Securities |
Prior to closing of this offering, the Company will enter into a series of reorganization transactions pursuant to which all of the outstanding common units and preferred units in Peak E&P, all of the outstanding ownership interests in PBLM and the equity in PSI held by Yorktown VIII and Yorktown IX will be contributed to the Company in exchange for certain limited partnership interests in the Company. See “Prospectus Summary — Reorganization Transactions, Partnership Structure and Expected Refinancing Transaction — Reorganization Transactions and Partnership Structure.”
The above issuances will not involve any underwriters, underwriting discounts or commissions, or any public offering and we believe such issuances are exempt from the registration requirements of the Securities Act by virtue of Section 4(a)(2) thereof.
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| Item 16. | Exhibits and Financial Statement Schedules. |
| * | To be filed by amendment. |
| # | The schedules to this agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule will be furnished to the SEC upon request. |
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| Item 17. | Undertakings. |
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
The undersigned registrant hereby undertakes that:
| (1) | For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. |
| (2) | For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. |
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Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Durango, State of Colorado, on September 13, 2024.
Peak Resources LP
By: Peak Resources GP LLC, its general partner | ||
| By: | /s/ Jack E. Vaughn | |
Jack E. Vaughn Chief Executive Officer | ||
Each person whose signature appears below appoints Jack E. Vaughn and Justin M. Vaughn, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys in fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys in fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys in fact and agents or any of them or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on September 13, 2024.
Signature | Title | |
/s/ Jack E. Vaughn Jack E. Vaughn | Chief Executive Officer and Chairman of the Board (Principal Executive Officer) | |
/s/ Justin M. Vaughn Justin M. Vaughn | Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | |
/s/ Ali A. Kouros Ali A. Kouros | Executive Vice President, Corporate Development and Strategy and Director | |
/s/ Bryan H. Lawrence Bryan H. Lawrence | Director | |
/s/ Bryan R. Lawrence Bryan R. Lawrence | Director | |
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