UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
☒ANNUAL REPORT PURSUANT TO SECTION 13
OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31,
2023
☐TRANSITION REPORT PURSUANT TO SECTION
13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
HNR ACQUISITION CORP
(Exact name of registrant as specified in its
charter)
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including
area code: (713)834-1145
Not Applicable
(Former name or former address, if changed
since last report)
Securities registered pursuant to Section 12(b)
of the Act:
Title of Each Class: Trading Symbol: Name of Each Exchange on Which Registered:
Class A Common Stock, par value $0.0001 per share HNRA NYSE American LLC
Securities registered pursuant to Section 12(g)
of the Act: None
Indicate by check mark if the registrant is a
well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not
required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒
Indicate by check mark whether the registrant
(1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant
has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405
of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No
☐
Indicate by check mark whether the registrant
is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.
See definition 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 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant
has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial
reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared
or issued its audit report. ☐
If securities are registered pursuant to Section
12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction
of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error
corrections are restatements that require a recovery analysis of incentive-based compensation received by any of the registrant’s
executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant
is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the Registrant was approximately
$47.9 million based on the last sale price on June 30, 2023.
As of May 2, 2024, 5,235,131 shares of Class
A Common Stock, par value $0.0001 per share, and 1,800,000 share of Class B Common Stock, par value $0.0001 per share, were issued and
outstanding.
TABLE
OF CONTENTS
PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS iii
PART I 1
Item 1 Business 1
Item 1.A. Risk Factors 26
Item 1.B. Unresolved Staff Comments 55
Item 1.C. Cybersecurity 55
Item 2. Properties 55
Item 3. Legal Proceedings 55
Item 4. Mine Safety Disclosures 55
Item 6. [Reserved] 59
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 68
Item 8. Financial Statements and Supplementary Data 68
Item 9A. Controls and Procedures 68
Item 9B. Other Information. 69
Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections. 69
PART III 70
Item 10. Directors, Executive Officers and Corporate Governance 70
Item 11. Executive Compensation 76
Item 14. Principal Accountant Fees and Services 91
Item 15. Exhibits and Financial Statement Schedules 92
i
CERTAIN TERMS
Unless otherwise stated in this Annual Report on Form 10-K (this
“Report”), or the context otherwise requires, references to:
● “management” or our “management team” are to our officers and directors;
● “Sponsor” refers to HNRAC Sponsors, LLC, a Delaware limited liability company;
ii
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Some statements contained in this Report may
constitute “forward-looking statements” for purposes of United States federal securities laws. Our forward-looking statements
include, but are not limited to, statements regarding our or our management team’s expectations, hopes, beliefs, intentions or
strategies regarding the future. In addition, any statements that refer to projections, forecasts or other characterizations of future
events or circumstances, including any underlying assumptions, are forward-looking statements. The words “anticipate,”
“believe,” “continue,” “could,” “estimate,” “expect,” “intends,”
“may,” “might,” “plan,” “possible,” “potential,” “predict,” “project,”
“should,” “would” and similar expressions may identify forward-looking statements, but the absence of these
words does not mean that a statement is not forward-looking. Forward-looking statements in this report may include, for example,
statements about:
● our expectations around the performance of our business;
● our potential ability to obtain additional financing;
● the level of production on our properties;
● our public securities’ potential liquidity and trading;
● the lack of a market for our securities;
● competition in the oil and natural gas industry;
● the trust account not being subject to claims of third parties; or
● future operating results.
The forward-looking statements contained
in this Report are based on our current expectations and beliefs concerning future developments and their potential effects on us. There
can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements
involve a number of risks, uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or
performance to be materially different from those expressed or implied by these forward-looking statements. These risks and uncertainties
include, but are not limited to, those factors described under the heading “Risk Factors.” Should one or more of these
risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from
those projected in these forward-looking statements. We undertake no obligation to update or revise any forward-looking statements,
whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. These
risks and others described under “Risk Factors” may not be exhaustive.
By their nature, forward-looking statements involve
risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. We caution
you that forward-looking statements are not guarantees of future performance and that our actual results of operations, financial condition
and liquidity, and developments in the industry in which we operate may differ materially from those made in or suggested by the forward-looking
statements contained in this Report. In addition, even if our results or operations, financial condition and liquidity, and developments
in the industry in which we operate are consistent with the forward-looking statements contained in this Report, those results or developments
may not be indicative of results or developments in subsequent periods.
iii
SUMMARY OF SIGNIFICANT RISKS AFFECTING OUR COMPANY
Our business is subject to multiple risks and uncertainties, as more
fully described in “Risk Factors” and elsewhere in this Annual Report on Form 10-K. We urge you to read the disclosures under
the caption “Risk Factors” and this Annual Report in full. Our significant risks may be summarized as follows:
iv
PART I
ITEM 1. BUSINESS
Overview
HNR Acquisition Corp, was incorporated in Delaware
as a blank check company formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization
or similar business combination with one or more businesses or entities. Prior to closing the Purchase, our efforts were limited to organizational
activities, completion of an initial public offering and the evaluation of possible business combinations. On February 15, 2022, we consummated
the Initial Public Offering of 7,500,000 units (the “Units”), at $10.00 per Unit, generating proceeds of $75,000,000. Additionally,
the underwriter fully exercised its option to purchase 1,125,000 additional Units, for which we received cash proceeds of $11,250,000.
Simultaneously with the closing of the Initial Public Offering, we consummated the sale of 505,000 private placement units at a price
of $10.00 per unit generating proceeds of $5,050,000 in a private placement to our Sponsor and EF Hutton (formerly Kingswood Capital
Markets) (“EF Hutton”). On April 4, 2022, the Units separated into Class A Common Stock and warrants, and ceased trading.
On April 4, 2022, the Class A Common Stock and warrants commenced trading on the NYSE American.
We identified as the initial target for our initial
business combination. Our efforts to identify a prospective target business were limited to a particular industry or geographic region.
While we were permitted to pursue an acquisition opportunity in any industry or sector, we focused on assets used in exploring, developing,
producing, transporting, storing, gathering, processing, fractionating, refining, distributing or marketing of natural gas, natural gas
liquids, crude oil or refined products in North America.
Purchase
On December 27, 2022, we, entered into a
Membership Interest Purchase Agreement (the “Original MIPA”) with CIC Pogo LP, a Delaware limited partnership (“CIC”),
DenCo Resources, LLC, a Texas limited liability company (“DenCo”), Pogo Resources Management, LLC, a Texas limited liability
company (“Pogo Management”), 4400 Holdings, LLC, a Texas limited liability company (“4400” and, together with
CIC, DenCo and Pogo Management, collectively, “Seller” and each a “Seller”), and, solely with respect to Section 7.20
of the Original MIPA, HNRAC Sponsors LLC, a Delaware limited liability company (“Sponsor”). On August 28, 2023, we,
HNRA Upstream, LLC, a newly formed Delaware limited liability company which is managed by us, and is a subsidiary of ours (“OpCo”),
and HNRA Partner, Inc., a newly formed Delaware corporation and wholly owned subsidiary of ours (“SPAC Subsidiary”, and together
with us and OpCo, “Buyer” and each a “Buyer”), entered into an Amended and Restated Membership Interest Purchase
Agreement (the “A&R MIPA”) with Seller, and, solely with respect to Section 6.20 of the A&R MIPA, the Sponsor,
which amended and restated the Original MIPA in its entirety (as amended and restated, the “MIPA”). Our stockholders approved
the transactions contemplated by the MIPA at a special meeting of stockholders that was originally convened October 30, 2023, adjourned,
and then reconvened on November 13, 2023 (the “Special Meeting”).
On November 15, 2023 (the “Closing Date”),
as contemplated by the MIPA:
1
The “Aggregate Consideration” for
the Target Interests was: (a) cash in the amount of $31,074,127 in immediately available funds (the “Cash Consideration”),
(b) 2,000,000 Class B common units of OpCo (“OpCo Class B Units”) valued at $10.00 per unit (the “Common Unit Consideration”),
which will be equal to and exchangeable into 2,000,000 shares of Class A Common Stock issuable upon exercise of the OpCo Exchange Right
(as defined below), as reflected in the amended and restated limited liability company agreement of OpCo that became effective at Closing
(the “A&R OpCo LLC Agreement”), (c) the Seller Class B Shares, (d) $15,000,000 payable through a promissory note to Seller
(the “Seller Promissory Note”), (e) 1,500,000 preferred units (the “OpCo Preferred Units” and together with the
Opco Class A Units and the OpCo Class B Units, the “OpCo Units”) of OpCo (the “Preferred Unit Consideration”,
and, together with the Common Unit Consideration, the “Unit Consideration”), and (f) an agreement for Buyer, on or before
November 21, 2023, to settle and pay to Seller $1,925,873 from sales proceeds received from oil and gas production attributable to Pogo,
including pursuant to its third party contract with affiliates of Chevron. At Closing, 500,000 Seller Class B Shares (the “Escrowed
Share Consideration”) were placed in escrow for the benefit of Buyer pursuant to an escrow agreement and the indemnity provisions
in the MIPA. The Aggregate Consideration is subject to adjustment in accordance with the MIPA.
In connection with the Purchase, holders of 3,323,707
shares of common stock sold in HNRA’s initial public offering (the “public shares”) properly exercised their right
to have their public shares redeemed (the “Redemption Rights”) for a pro rata portion of the trust account (the “Trust
Account”) which held the proceeds from HNRA’s initial public offering, funds from HNRA’s payments to extend the time
to consummate a business combination and interest earned, calculated as of two business days prior to the Closing, which was approximately
$10.95 per share, or $49,362,479 in the aggregate. The remaining balance in the Trust Account (after giving effect to the Redemption
Rights) was $12,979,300.
Immediately upon the Closing, Pogo Royalty exercised
the OpCo Exchange Right as it relates to 200,000 OpCo Class B units (and 200,000 shares of Class B Common Stock). After giving effect
to the Purchase, the redemption of public shares as described above and the exchange mentioned in the preceding sentence, were (i) 5,097,009
shares of Class A Common Stock issued and outstanding, (ii) 1,800,000 shares of Class B Common Stock issued and outstanding and (iii)
no shares of preferred stock issued and outstanding.
The Class A Common Stock and HNRA warrants continued
to trade, but now as an operating company, on the NYSE American under the symbols “HNRA” and “HNRAW,” respectively,
on November 16, 2023.
First Amendment to Amended and Restated
Membership Interest Purchase Agreement
On November 15, 2023, Buyer, Seller, and Sponsor
entered into the MIPA Amendment, whereby the Parties agreed to extend the outside date for the transaction to November 30, 2023, and
to place 500,000 shares of Seller Class B Shares into escrow instead of 500,000 OpCo Class B Units.
2
Settle Up Letter Agreement
On November 15, 2023, Buyer and Seller entered
into the Settle Up Letter Agreement, whereby Seller agreed to accept a minimum amount of cash at Closing less than $33,000,000, provided
that, on or before November 21, 2023, Buyer must settle and pay to Seller $1,925,873 from sales proceeds received from oil and gas production
attributable to Pogo, including pursuant to its third party contract with affiliates of Chevron.
OpCo A&R LLC Agreement
In connection with the Closing, HNRA and Pogo
Royalty, LLC, a Texas limited liability company, an affiliate of Seller and Seller’s designated recipient of the Aggregate Consideration
(“Pogo Royalty”), entered into an amended and restated limited liability company agreement of OpCo (the “OpCo A&R
LLC Agreement”). Pursuant to the A&R OpCo LLC Agreement, each OpCo unitholder (excluding HNRA) will, subject to certain timing
procedures and other conditions set forth therein, have the right (the “OpCo Exchange Right”) to exchange all or a portion
of its OpCo Class B Units for, at OpCo’s election, (i) shares of Class A Common Stock at an exchange ratio
of one share of Class A Common Stock for each OpCo Class B Unit exchanged, subject to conversion rate adjustments for stock
splits, stock dividends and reclassifications and other similar transactions, or (ii) an equivalent amount of cash. Additionally,
the holders of OpCo Class B Units will be required to exchange all of their OpCo Class B Units (a “Mandatory
Exchange”) upon the occurrence of the following: (i) upon the direction of HNRA with the consent of at least fifty percent
(50%) of the holders of OpCo Class B Units; or (ii) upon the one-year anniversary of the Mandatory Conversion Trigger
Date. In connection with any exchange of OpCo Class B Units pursuant to the OpCo Exchange Right or acquisition of OpCo Class B
Units pursuant to a Mandatory Exchange, a corresponding number of shares of Class B Common Stock held by the relevant OpCo
unitholder will be cancelled.
The OpCo Preferred Units will be automatically
converted into OpCo Class B Units on the two-year anniversary of the issuance date of such OpCo Preferred Units (the
“Mandatory Conversion Trigger Date”) at a rate determined by dividing (i) $20.00 per unit (the “Stated Conversion
Value”), by (ii) the Market Price of the Class A Common Stock (the “Conversion Price”). The “Market
Price” means the simple average of the daily VWAP of the Class A Common Stock during the five (5) trading days prior
to the date of conversion. On the Mandatory Conversion Trigger Date, HNRA will issue a number of shares of Class B Common Stock
to Pogo Royalty equivalent to the number of OpCo Class B Units issued to Pogo Royalty. If not exchanged sooner, such newly
issued OpCo Class B Units shall automatically exchange into Class A Common Stock on the one-year anniversary of the
Mandatory Conversion Trigger Date at a ratio of one OpCo Class B Unit for one share of Class Common Stock. An equivalent number
of shares of Class B Common Stock must be surrendered with the OpCo Class B Units to us in exchange for the Class A
Common Stock. As noted above, the OpCo Class B Units must be exchanged upon the one-year anniversary of the Mandatory Conversion
Trigger Date.
Promissory Note
In connection with the Closing, OpCo issued the Seller Promissory Note
to Pogo Royalty in the principal amount of $15,000,000. The Seller Promissory Note provides for a maturity date that is six (6) months
from the Closing Date, bears an interest rate equal to 12% per annum, and contains no penalty for prepayment. If the Seller Promissory
Note is not repaid in full on or prior to its stated maturity date, OpCo will owe interest from and after default equal to the lesser
of 18% per annum and the highest amount permissible under law, compounded monthly. The Seller Promissory Note is subordinated to the Term
Loan (as defined herein).
Registration Rights Agreement
In connection with the Closing, HNRA and Pogo
Royalty entered into a Registration Rights Agreement (the “Registration Rights Agreement”), pursuant to which HNRA has agreed
to provide Pogo Royalty with certain registration rights with respect to the shares of Class A Common Stock issuable upon exercise of
the OpCo Exchange Right, including filing with the SEC an initial registration statement on Form S-1 covering the resale by
the Pogo Royalty of the shares of Class A Common Stock issuable upon exercise of the OpCo Exchange Right so as to permit their resale
under Rule 415 under the Securities Act, no later than thirty (30) days following the Closing, use its commercially reasonable
efforts to have the initial registration statement declared effective by the SEC as soon as reasonably practicable following the filing
thereof with the SEC, and use commercially reasonable efforts to convert the Form S-1 (and any subsequent registration statement)
to a shelf registration statement on Form S-3 as promptly as practicable after HNRA is eligible to use a Form S-3 Shelf.
In certain circumstances, Pogo Royalty can demand
our assistance with underwritten offerings, and Pogo Royalty will be entitled to certain piggyback registration rights.
3
Option Agreement
In connection with the Closing, HNRA, HNRA Royalties,
LLC, a newly formed Delaware limited liability company and wholly-owned subsidiary of HNRA (“HNRA Royalties”) and Pogo Royalty
entered into an Option Agreement (the “Option Agreement”). Pogo Royalty owns certain overriding royalty interests in certain
oil and gas assets owned by Pogo (the “ORR Interest”). Pursuant to the Option Agreement, Pogo Royalty granted irrevocable
and exclusive option to HNRA Royalty to purchase the ORR Interest for the Option Price (as defined below) at any time prior to November
15, 2024. The option is not exercisable while the Seller Promissory Note is outstanding.
The purchase price for the ORR Interest upon
exercise of the option is: (i) (1) $30,000,000 the (“Base Option Price”), plus (2) an additional amount equal
to interest on the Base Option Price of twelve percent (12%), compounded monthly, from the Closing Date through the date of acquisition
of the ORR Interest, minus (ii) any amounts received by Pogo Royalty in respect of the ORR Interest from the month of production
in which the effective date of the Option Agreement occurs through the date of the exercise of the option (such aggregate purchase price,
the “Option Price”).
The Option Agreement and the option will immediately
terminate upon the earlier of (a) Pogo Royalty’s transfer or assignment of all of the ORR Interest in accordance with the
Option Agreement and (b) November 15, 2024.
Pursuant to the Option Agreement, upon execution,
HNRA issued to Pogo Royalty 10,000 shares of Class A Common Stock.
Director Nomination and Board Observer
Agreement
In connection with the Closing, we entered into
Director Nomination and Board Observer Agreement (the “Board Designation Agreement”) with CIC. Pursuant to the Board Designation
Agreement, CIC has the right, at any time CIC beneficially owns our capital stock, to appoint two board observers to attend all meetings
of our Board of Directors. In addition, after the time of the conversion of the OpCo Preferred Units owned by Pogo Royalty, CIC
will have the right to nominate a certain number of members of the board of directors depending on Pogo Royalty’s ownership percentage
of Class A Common Stock as further provided in the Board Designation Agreement.
Backstop Agreement
In connection with the Closing, HNRA entered
a Backstop Agreement (the “Backstop Agreement”) with Pogo Royalty and certain of HNRA’s founders listed therein (the
“Founders”) whereby Pogo Royalty will have the right (“Put Right”) to cause the Founders to purchase Pogo Royalty’s
OpCo Preferred Units at a purchase price per unit equal to $10.00 per unit plus the product of (i) the number of days
elapsed since the effective date of the Backstop Agreement and (ii) $10.00 divided by 730. Seller’s right to exercise the
Put Right will survive for six (6) months following the date the Trust Shares (as defined below) are not restricted from transfer
under the Letter Agreement (as defined in the MIPA) (the “Lockup Expiration Date”).
As security that the Founders will be able to
purchase the OpCo Preferred Units upon exercise of the Put Right, the Founders agreed to place at least 1,300,000 shares of
Class A Common Stock into escrow (the “Trust Shares”), which the Founders can sell or borrow against to meet their obligations
upon exercise of the Put Right, with the prior consent of Seller. HNRA is not obligated to purchase the OpCo Preferred Units from
Pogo Royalty under the Backstop Agreement. Until the Backstop Agreement is terminated, Pogo Royalty and its affiliates are not permitted
to engage in any transaction which is designed to sell short the Class A Common Stock or any other publicly traded securities of
HNRA.
4
Founder Pledge Agreement
In connection with the Closing, HNRA entered
a Founder Pledge Agreement (the “Founder Pledge Agreement”) with the Founders whereby, in consideration of placing
the Trust Shares into escrow and entering into the Backstop Agreement, HNRA agreed: (a) by January 15, 2024, to issue to the Founders
an aggregate number of newly issued shares of Class A Common Stock equal to 10% of the number of Trust Shares; (b) by January 15, 2024,
to issue to the Founders number of warrants to purchase an aggregate number of shares of Class A Common Stock equal to 10% of the number
of Trust Shares, which such warrants shall be exercisable for five years from issuance at an exercise price of $11.50 per shares; (c)
if the Backstop Agreement is not terminated prior to the Lockup Expiration Date, to issue an aggregate number of newly issued shares
of Class A Common Stock equal to (i) (A) the number of Trust Shares, divided by (B) the simple average of the daily VWAP of the
Class A Common Stock during the five (5) Trading Days prior to the date of the termination of the Backstop Agreement, subject to a minimum
of $6.50 per share, multiplied by (C) a price between $10.00-$13.00 per share (as further described in the Founder Pledge Agreement),
minus (ii) the number of Trust Shares; and (d) following the purchase of OpCo Preferred Units by a Founder pursuant to the Put
Right, to issue a number of newly issued shares of Class A Common Stock equal to the number of Trust Shares sold by such Founder. Until
the Founder Pledge Agreement is terminated, the Founders are not permitted to engage in any transaction which is designed to sell short
the Class A Common Stock or any other publicly traded securities of HNRA.
Pogo Overview
Pogo is an exploration and production company
that began operations in February 2017. Pogo is based in Dallas, Texas, and a field office in Loco Hills, New Mexico. As of December 31,
2023, Pogo’s operating focus is the Northwest Shelf of the Permian Basin, with a specific emphasis on oil and gas producing properties
located in the Grayburg-Jackson Field in Eddy County, New Mexico. Pogo is the Operator of Record of its oil and gas properties,
operating its properties through its wholly owned subsidiary, LH Operating LLC. Pogo completed multiple acquisitions in 2018 and
2019. These acquisitions included multiple producing properties in Lea and Eddy counties, New Mexico. In 2020, after identifying
its core development property, Pogo successfully completed a series of divestures of its non-core properties. Then, with one key
asset, its Grayburg-Jackson Field in Eddy County, New Mexico, Pogo focused all of its efforts on developing this asset. This has
been Pogo’s focus for 2022 and 2023. Currently, Pogo and HNRA combined have 15 employees (5 executive officers where 4 are in Houston
and 1 in Lubbock; 10 field staff in Loco Hills). From time to time, on an as needed basis, contract workers handle additional necessary
responsibilities.
Pogo owns, manages, and operates, through its
wholly owned subsidiary, LH Operating, LLC, 100% working interest in a gross 13,700 acres located on the Northwest Shelf of the prolific
oil and gas producing Permian Basin. Pogo benefits from cash flow growth through continued development of its working interest’s
ownership, with relatively low capital cost and lease operating expenses. As of December 31, 2023, average net daily production
associated with Pogo’s working interests was 1,022 barrel of oil equivalent (“BOE”) per day consisting of 94%
oil and 6% natural gas. Pogo expects to continue to grow its cash flow by production enhancements in its operations on its gross 13,700-acre leasehold.
Furthermore, Pogo intends to make additional acquisitions within the Permian Basin, as well as other oil and gas producing regions in
the USA, that meet its investment criteria for minimum risk, geologic quality, operator capability, remaining growth potential, cash
flow generation and, most importantly, rate of return.
As of December 31, 2023, 100% of Pogo’s
gross 13,700 leasehold acres were located in Eddy County, New Mexico, where there 100% of the leasehold working interests owned by Pogo
consist of state and federal lands. Pogo believes the Permian Basin offers some of the most compelling rates of return for Pogo and significant
potential for cash flow growth. As a result of compelling rates of return, development activity in the Permian Basin has outpaced all
other onshore U.S. oil and gas basins since the end of 2016. This development activity has driven basin-level production to
grow faster than production in the rest of the United States.
5
Pogo’s working interests entitle it to
receive an average of 97% of the net revenue from crude oil and natural gas produced from the oil and gas reservoirs underlying its acreage.
Pogo is not under any mandatory obligation to fund drilling and completion costs associated with oil and gas development because 100%
of its lease holdings are held by production. As a working interest owner with significant net earnings, Pogo seeks to fully capture
all remaining oil and gas reserves underlying its leasehold acres by systematically developing its low risk, predictable, proven reserves
by means of adding perforations in previously drilled and completed wells, were applicable, and drilling new wells in a predetermined
drilling pattern. Accordingly, Pogo’s development model generates strong margins greater than 60%, at low risk, predictable, production
outcomes that requires low overhead and is highly scalable. For the year ended December 31, 2023, Pogo’s lifting cost was
about $27.21 per barrel of oil equivalent at a realized price of $72.69 per BOE, excluding the impact of settled commodity derivatives.
Pogo is led by a management team with extensive oil and gas engineering, geologic and land expertise, long-standing industry relationships
and a history of successfully managing a portfolio of working and leasehold interests, producing crude oil and natural gas assets. Pogo
intends to capitalize on its management team’s expertise and relationships to increase production and cash flow in the field.
Pogo Market Conditions
The price that Pogo receives for the oil and
natural gas we produce is largely a function of market supply and demand. Because Pogo’s oil and gas revenues are heavily weighted
toward oil, Pogo is more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply
in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength
of the U.S. dollar can adversely impact oil prices.
Historically, commodity prices have been volatile,
and Pogo expects the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand
for oil, as well as the growth in domestic oil production.
Pogo’s Key Producing Region
As of December 31, 2023, all of Pogo’s
properties were located exclusively within the Northwest Shelf of the Permian Basin. As of December 2023, the Permian Basin had
the highest level of drilling activity in the United States with greater than 300 drilling rigs operating. By comparison, The Eagle
Ford Shale region located in Southwest-central Texas has less than 60 rigs operating. The Permian Basin includes three major geologic
provinces: the Delaware Basin to the west, the Midland Basin to the east and the Central Basin Platform in between. The Northwest Shelf
is the western limits of the Delaware Basin, a sub-basin within the Permian Basin complex. The Delaware Basin is identified by an
abundant amount of oil-in-place, stacked pay potential across an approximately 3,900-foot hydrocarbon column, attractive well economics,
favorable operating environment, well developed network of oilfield service providers, and significant midstream infrastructure in place
or actively under construction. One hundred percent (100%) of Pogo’s working interests are located as of December 31, 2023,
on the New Mexico side of the Delaware Basin. According to the USGS, the Delaware Basin contains the largest recoverable reserves among
all unconventional basins in the United States.
We believe the stacked-play potential of the
Delaware Basin combined with favorable drilling economics support continued production growth as Pogo develops its leasehold position
and improve well-spacing and completion techniques. Relative to other basins in the continental United States, Pogo believes the Delaware
Basin is in a mid-stage of well development and that per-well returns will improve as Pogo continues to employ enhanced oil recovery
technologies on its leasehold acreage. Pogo believes these enhanced oil recoveries will continue to support development activity where
it holds significant working interest, with predictable returns leading to increasing cash flows with low maintenance costs.
Pogo’s Working Interests in Grayburg-Jackson Field
As of December 31, 2023, Pogo owns 100%
working interest in 13,700 gross acres located in Eddy County, New Mexico, with a 74% weighted average net revenue. The 13,700 gross
acres are strategically located in the prolific oil field, Grayburg-Jackson field. Working interests granted to the Lessee (Pogo)
under an Oil and Gas Lease are real property interests that grant ownership of the crude oil and natural gas underlying a specific tract
of land and the rights to explore for, drill for and produce crude oil and natural gas on that land or to lease those exploration and
development rights to a third party. Those rights to explore for, drill for and produce crude oil and natural gas on that land have a
set period of time for the working interest owner to exercise those rights. Typically, an Oil and Gas Lease can be automatically extended
beyond the initial lease term with continuous drilling, production or other operating activities or through negotiated contractual lease
extension options. Only when production and drilling cease, the lease terminates.
6
As of December 31, 2023, 100% of Pogo’s
working interests are held by production (“HBP”) meaning that Pogo is not under time sensitive obligation to drill or work-over any
wells on its 13,700 acres. As of December 31, 2023, 100% of the wells and leases are operated by Pogo. Pogo is the official Operator
of record with the state and federal regulatory agencies. As of December 31, 2023, Pogo generates a substantial majority of its
revenues and cash flows from its working interests when crude oil and natural gas are produced and sold from its acreage.
Currently, Pogo’s working interests reside
entirely in the Northwest Shelf of the Permian Basin, which Pogo believes is one of the premier crude oil and natural gas producing regions
in the United States. As of December 31, 2023, Pogo’s working interests covered 13,700 gross acres, with the royalty
owners retaining a weighted average 26% royalty. The following table summarizes Pogo’s working interest’s position in the
lands comprising its leasehold as of December 31, 2023.
LH Operating, LLC Northwest Shelf (Permian Basin) Leasehold
(2) No unleased royalty interests as of December 31, 2023.
As of December 31, 2023, Pogo has working interests in 341 shallow
(above 4,000 ft), vertical wells producing oil and gas in paying quantities. Ninety-five of the 341 producing wells were completed
between 2019 and June 2022 by Pogo. In 2019, Pogo initiated a 4-well pilot water injection project into the Seven Rivers (“7R”)
oil reservoir underlying its 13,700-acre leasehold. After an evaluation period extending into early 2020, Pogo determined the pilot
project was successful by producing oil in paying quantities by simply adding perforations in the 7R reservoir in previously drilled and
completed wells. Following the successful completion of the 4-well pilot project, Pogo commenced a work-over program by adding
perforations in the 7R reservoir in 91 previously drilled wells between 2019 and June 2022. Prior to initiating the 4-well pilot
project the legacy wells were averaging 275 BOE/d. By December 2023, the total production increased to 1,022 BOE/d. Pogo’s management
team has determined, and verified by William M. Cobb & Associates (“Cobb & Associates”), that 115 proved
well patterns, developed but non-producing, are scheduled to be brought into production between 2024 and 2027.
As of December 31, 2023, the estimated proved
crude oil and natural gas reserves attributable to Pogo’s interests in its underlying acreage were 16,002 MBOE (96% oil and 4%
natural gas), based on a reserve report prepared by Cobb & Associates, worldwide petroleum consultants. Of these reserves, approximately
26% were classified as proved developed producing (“PDP”) reserves, 47% were classified as proved developed non-producing (“PDNP”)
reserves and 27% were classified as proved undeveloped (“PUD”) reserves. PUD reserves included in these estimates relate
solely to wells that are not yet drilled nor were not yet producing in paying quantities as of December 31, 2023. Estimated proved
reserves included in this section is presented on an actual basis, without giving pro forma effect to transactions completed after such
dates.
Pogo believes its production and discretionary
cash flows will grow significantly as Pogo completes its substantial PDNP inventory of 7R well patterns located on its gross 13,700 acreage.
As of December 31, 2023, Pogo had production from 342 vertical wells, and it has identified 115 additional PDNP well patterns based
on its assessment of current geological, engineering and land data. As of December 31, 2023, Pogo has identified 43 PUD well patterns
based on its assessment of current geological, engineering and land data
Pogo’s working interest development strategy
anticipates shifting any drilling activity associated with its PUD reserves following Pogo’s completion of its PDNP reserves. The
work-over costs attributable to adding perforations in wells previously drilled and completed is significantly less than drilling
new wells. As of December 31, 2023, Pogo’s leasehold position has 25.7 wells per square mile. Pogo expects to see increases
in its production, revenue and discretionary cash flows from the development of 115 well patterns in the 7R reservoir. Pogo believes
its current leasehold working interests provide the potential for significant long-term organic revenue growth as Pogo develops
its PDNP reserves to increase crude oil and natural gas production.
7
Pogo Business Strategies
Pogo’s primary business objective is to generate discretionary
cash flow by maintaining its strong cash flow from the PDP reserves and increasing cash flow by developing predictable, low cost PDNP
reserves in its Permian Basin asset. Pogo intends to accomplish this objective by executing the following strategies:
Generate strong cash flow supported by
means of disciplined development of its PDNP Reserves. As the sole working interest owner, Pogo benefits from the continued organic
development of its acreage in the Permian Basin. As of December 31, 2023, Pogo, in conjunction with Cobb & Associates,
a third-party engineering consulting firm, has confirmed that Pogo has 115, low cost, well patterns to be developed during 2024
to 2027. The total costs to complete these 115 well patterns have been predetermined by historical analysis. The estimated cost to complete
each PDNP pattern is $345,652 and the estimated cost to complete each PUD pattern is $1,187,698. A single well pattern consists of one
each producing well with its corresponding or dedicated water injection wells, with each injection well situated on four sides of the
producing well. Water injection wells are necessary to maintain reservoir pressure in its original state and to move the oil in place
toward the producing well. Pressure maintenance helps ensure maximum oil and gas recovery. Without pressure maintenance, oil recoveries
from a producing oil reservoir generally do not exceed 10% of the original oil in place (“OOIP”). With pressure maintenance
by re-injecting produced water into the oil reservoir, then Pogo expects to see ultimate oil recoveries 25% or greater of the OOIP. Offsetting
oil wells on its leasehold also take advantage of the water injected into the oil reservoir, and is able to convert a high percentage
of its revenue to discretionary cash flow. Because Pogo owns 100% working interests it incurs 100% of the monthly leasehold operating
costs for the production of crude oil and natural gas or capital costs for the drilling and completion of wells on its acreage. Because
these wells are shallow oil producers, with vertical depths between 1500 ft and 4000 ft, the monthly operating expenses are relatively
low.
Focus primarily on the Permian Basin. All
of Pogo’s working interests are currently located in the Permian Basin, one of the most prolific oil and gas basins in the United States.
Pogo believes the Permian Basin provides an attractive combination of highly-economic and oil-weighted geologic and reservoir
properties, opportunities for development with significant inventory of drilling locations and zones to be delineated our top-tier management
team.
● sufficient visibility to production growth;
● attractive economics;
● de-risked geology supported by stable production;
● targets from top-tier E&P operators; and
8
Maintain conservative and flexible capital
structure to support Pogo’s business and facilitate long-term operations. Pogo is committed to maintaining a conservative
capital structure that will afford it the financial flexibility to execute its business strategies on an ongoing basis. Pogo believes
that internally generated cash flows from its working interests and operations, available borrowing capacity under its revolving credit
facility, and access to capital markets will provide it with sufficient liquidity and financial flexibility to continue to acquire attractive
targets with high working interests that will position it to grow its cash flows in order to distributed to its shareholders as dividends
and/or reinvested to further expand its base of cash flow generating assets. Pogo intends to maintain a conservative leverage profile
and utilize a mix of cash flows from operations and issuance of debt and equity securities to finance future acquisitions.
Pogo Competitive Strengths
Pogo believes that the following competitive
strengths will allow it to successfully execute its business strategies and achieve its primary business objective:
9
Pogo Crude Oil and Natural Gas Data
In this report, we include estimates of reserves associated with the
assets located in New Mexico as of December 31, 2022, and December 31, 2023. Such reserve estimates are based on evaluations prepared
by the independent petroleum engineering firm of Cobb & Associates, 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. The December 31, 2022 and December 31, 2023 reserve reports include the total interests of Pogo Resources, LLC,
including the 10% overriding royalty interest not acquired in the Purchase, and are included in this filing. As such, the estimates of
proved oil and gas and discounted future net cash flows include the total interests of Pogo Resources, LLC.
Cobb & Associates, Inc. is an independent
consulting firm founded in 1983. Its compensation is not contingent on the results obtained or reported. Frank J. Marek, a Registered
Texas Professional Engineer and a senior technical advisor of Cobb & Associates, Inc., is primarily responsible for overseeing
the preparation of the reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators set forth
in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of
Petroleum Engineers. His qualifications include: Bachelor of Science degree in Petroleum Engineering from Texas A&M University 1977;
member of the Society of Petroleum Engineers; member of the Society of Petroleum Evaluation Engineers; and 40 years of experience
in estimating and evaluating reserve information and estimating and evaluating reserves; he is proficient in judiciously applying industry
standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
Preparation of Reserve Estimates
Pogo’s reserve estimates as of December 31,
2022 and December 31, 2023 included in this report is included are based on evaluations prepared by the independent petroleum engineering
firm of Cobb & Associates 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. The December 31,
2022 and December 31, 2023 reserve reports include the total interests of Pogo Resources, LLC, including the 10% overriding royalty interest
not acquired in the Purchase, and are included in this filing. As such, the estimates of proved oil and gas and discounted future net
cash flows include the total interests of Pogo Resources, LLC. Pogo selected Cobb & Associates as its independent reserve
engineer for its historical experience and geographic expertise in engineering similar resources.
In accordance with rules and regulations of the
SEC applicable to companies involved in crude oil and natural gas producing activities, proved reserves are those quantities of crude
oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government
regulations. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are
much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal
to or exceeding the estimate. All of Pogo’s proved reserves 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 crude 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 reserves relies on the use
of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production
performance-based methods, (ii) material balance-based methods; (iii) volumetric-based methods and (iv) 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 proved developed producing wells were estimated using production performance methods. Non-producing reserve estimates, for developed
and undeveloped properties, were forecast using a pattern simulation model.
To estimate economically recoverable proved reserves
and related future net cash flows, Pogo considered many factors and assumptions, including the use of reservoir parameters derived from
geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements
and forecasts of future production rates.
10
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 have been field tested and have 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 Pogo’s estimated proved reserves, the technologies and economic data used in the estimation of its 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 data, and historical well cost and operating expense
data.
Pogo Internal Controls
Pogo’s internal staff of petroleum engineers
and geoscience professionals work closely with its independent reserve engineer to ensure the integrity, accuracy and timeliness of data
furnished to such independent reserve engineer in their preparation of reserve estimates. 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. See “Risk Factors Related to
Our Business” appearing elsewhere in this report. Pogo’s engineering group is responsible for the internal review of
reserve estimates.
No portion of Pogo’s engineering group’s
compensation is directly dependent on the quantity of reserves booked. The engineering group reviews the estimates with the third-party petroleum
consultant, Cobb & Associates, an independent petroleum engineering firm.
Pogo Reconciliation of Standardized Measure
to PV-10
Neither PV-10 nor PV-10 after ARO are financial
measures defined under accounting principles generally accepted in the United States of America (“GAAP”); therefore, the
following table reconciles these amounts to the standardized measure of discounted future net cash flows, which is the most directly
comparable GAAP financial measure. Management believes that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant
and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 and PV-10 after ARO are used internally
when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities.
Management believes that the presentation of PV-10 and PV-10 after ARO provide useful information to investors because they are widely
used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 and PV-10 after ARO are
not measures of financial or operating performance under GAAP, nor are they intended to represent the current market value of our estimated
oil and natural gas reserves. PV-10 after ARO is equivalent to the standardized measure of discounted future net cash flows as defined
under GAAP. Investors should not assume that PV-10, or PV-10 after ARO, of our proved oil and natural gas reserves shown above represent
a current market value of our estimated oil and natural gas reserves.
The reconciliation of PV-10 and PV-10 after ARO
to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves is as follows
(in thousands):
Present value of estimated future net revenues (PV-10) $ 281,018 $ 519,775
Present value of estimated ARO, discounted at 10% (173 ) (228 )
11
Pogo Summary of Reserves
The following table presents Pogo’s estimated
proved reserves as of December 31, 2023 and 2022. The December 31, 2023 and 2023 reserve reports include the total interests
of Pogo Resources, LLC, including the 10% overriding royalty interest not acquired in the Purchase, and are included in this filing as
exhibits. As such, the estimates of proved oil and gas and discounted future net cash flows include the total interests of Pogo Resources,
LLC. The reserve estimates presented in the table below are based on reports prepared by Cobb & Associates, Pogo’s independent
petroleum engineers, which reports were prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve
reporting:
Estimated proved developed producing reserves:
NGLs (MBbls) 0 0
Estimated proved non-producing reserves:
NGLs (MBbls) 0 0
Estimated proved undeveloped reserves:
NGLs (MBbls) 0 0
Estimated proved reserves:
NGLs (MBbls) 0 0
Reserve engineering is a process of estimating
volumes of economically recoverable crude 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 crude oil and natural gas that are ultimately recovered. Estimates
of economically recoverable crude 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 Related to Our Business.”
12
Pogo PUDs
As of December 31, 2022, Pogo estimated
its PUD reserves to be 4,564 MBbls of crude oil and 1,000 MMcf of natural gas for a total of 4,730 MBOE. As of December 31, 2023,
Pogo estimated its PUD reserves to be 4,137 MBbls of crude oil and 850 MMcf of natural gas for a total of 4,279 MBOE. PUDs will
be converted from undeveloped to developed as the applicable wells begin production.
The following table summarizes Pogo’s changes
in PUD reserves during the year ended December 31, 2022 (in MBOE):
Proved Undeveloped Reserves (MBOE)