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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): March 12, 2025 |
PHX MINERALS INC.
(Exact name of Registrant as Specified in Its Charter)
Delaware |
001-31759 |
73-1055775 |
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(State or Other Jurisdiction |
(Commission File Number) |
(IRS Employer |
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1320 South University Drive Suite 720 |
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Fort Worth, Texas |
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76107 |
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(Address of Principal Executive Offices) |
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(Zip Code) |
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Registrant’s Telephone Number, Including Area Code: (405) 948-1560 |
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(Former Name or Former Address, if Changed Since Last Report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
Securities registered pursuant to Section 12(b) of the Act:
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Trading |
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Common Stock, $0.01666 par value |
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PHX |
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New York Stock Exchange |
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).
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. ☐
Item 2.02 |
Results of Operations and Financial Condition. |
On March 12, 2025, PHX Minerals Inc. (the “Company”) issued a press release providing information regarding the Company’s quarter and year ended December 31, 2024 financial and operating results. The press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated by reference herein.
Item 7.01 |
Regulation FD Disclosure. |
The information set forth under Item 2.02 of this Current Report on Form 8-K is hereby incorporated in this Item 7.01 by reference.
On March 12, 2025, the Company posted an updated investor presentation to its website. A copy of the presentation is furnished as Exhibit 99.2 to this Current Report on Form 8-K.
The information in Item 2.02 and Item 7.01 of this Current Report on Form 8-K, including the attached Exhibits 99.1 and 99.2, is being furnished pursuant to Item 2.02 and Item 7.01 and shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, and shall not be deemed to be incorporated by reference into any of the Company’s filings under the Securities Act of 1933, as amended, or the Exchange Act, whether made before or after the date hereof and regardless of any general incorporation language in such filings, except to the extent expressly set forth by specific reference in such a filing.
Item 9.01 |
Financial Statements and Exhibits |
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(d) |
Exhibits. |
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Exhibit No. |
Title of Document |
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99.1 |
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99.2 |
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104 |
Cover Page Interactive Data File (embedded within the Inline XBRL document). |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
PHX MINERALS INC.
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By: |
/s/ Chad L. Stephens |
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Chad L. Stephens |
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Chief Executive Officer |
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DATE: |
March 12, 2025 |
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Exhibit 99.1
FOR IMMEDIATE RELEASE
PHX Minerals Reports Results for the Quarter and Year Ended Dec. 31, 2024
FORT WORTH, Texas, March 12, 2025 – PHX MINERALS INC., “PHX” or the “Company” (NYSE: PHX), today reported financial and operating results for the quarter and year ended Dec. 31, 2024.
Summary of Results for the Quarter and Year Ended Dec. 31, 2024
Subsequent Events
Chad L. Stephens, President and CEO, commented, “PHX delivered solid results in 2024. Notably, we achieved our highest total corporate production volumes for a full calendar year since 2019. We also recorded our two highest royalty production volume quarters in company history during 2024, specifically the second and third calendar quarters. The strength of our asset base allowed us to generate strong cash flow, reduce debt and return capital to stockholders through our dividend.” Mr. Stephens added, “We are continuing our previously announced process with RBC to evaluate possible strategic alternatives to maximize stockholder value.
“As referenced in our subsequent events, we closed on the sale of approximately 165,000 net mineral acres for $8.0 million. These minerals are old legacy minerals located in the U.S. on the margins of various basins with little to no near-term developmental resource potential, have no cash flow or reserve value associated with them and have had no leasing activity over the last 6 years,” concluded Mr. Stephens.
– 1 –
Financial Highlights
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Three Months Ended |
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Three Months Ended |
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Year Ended |
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Year Ended |
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Dec. 31, 2024 |
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Dec. 31, 2023 |
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Dec. 31, 2024 |
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Dec. 31, 2023 |
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Royalty Interest Sales |
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$ |
7,874,377 |
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$ |
7,378,650 |
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$ |
29,851,728 |
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$ |
31,593,351 |
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Working Interest Sales |
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$ |
1,011,545 |
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$ |
1,170,133 |
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$ |
3,838,924 |
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$ |
4,942,934 |
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Natural Gas, Oil and NGL Sales |
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$ |
8,885,922 |
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$ |
8,548,783 |
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$ |
33,690,652 |
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$ |
36,536,285 |
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Gains (Losses) on Derivative Contracts |
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$ |
(998,129 |
) |
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$ |
3,211,410 |
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$ |
299,608 |
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$ |
6,859,589 |
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Lease Bonuses and Rental Income |
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$ |
135,589 |
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$ |
22,780 |
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$ |
580,804 |
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$ |
1,068,022 |
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Total Revenue |
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$ |
8,023,382 |
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$ |
11,782,973 |
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$ |
34,571,064 |
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$ |
44,463,896 |
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Lease Operating Expense |
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per Working Interest Mcfe |
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$ |
1.09 |
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$ |
1.07 |
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$ |
1.14 |
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$ |
1.27 |
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Transportation, Gathering and |
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Marketing per Mcfe |
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$ |
0.43 |
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$ |
0.42 |
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$ |
0.46 |
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$ |
0.39 |
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Production and Ad Valorem Tax |
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per Mcfe |
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$ |
0.12 |
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$ |
0.20 |
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$ |
0.17 |
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$ |
0.20 |
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G&A Expense per Mcfe |
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$ |
1.22 |
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$ |
1.36 |
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$ |
1.19 |
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$ |
1.28 |
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Cash G&A Expense per Mcfe (1) |
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$ |
0.99 |
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$ |
1.10 |
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$ |
0.93 |
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$ |
1.02 |
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Interest Expense per Mcfe |
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$ |
0.24 |
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$ |
0.32 |
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$ |
0.26 |
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$ |
0.25 |
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DD&A per Mcfe |
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$ |
1.10 |
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$ |
1.09 |
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$ |
0.98 |
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$ |
0.91 |
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Total Expense per Mcfe |
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$ |
3.24 |
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$ |
3.53 |
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$ |
3.18 |
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$ |
3.20 |
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Net Income (Loss) |
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$ |
109,400 |
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$ |
2,513,444 |
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$ |
2,321,866 |
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$ |
13,920,800 |
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Adjusted EBITDA (2) |
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$ |
5,385,515 |
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$ |
4,504,288 |
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$ |
21,324,050 |
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$ |
22,652,263 |
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Cash Flow from Operations (3) |
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$ |
2,870,001 |
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$ |
3,361,455 |
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$ |
18,077,853 |
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$ |
24,171,139 |
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CapEx (4) |
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$ |
22,951 |
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$ |
4,587 |
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$ |
87,579 |
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$ |
325,983 |
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CapEx - Mineral Acquisitions |
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$ |
2,524,136 |
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$ |
4,351,757 |
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$ |
7,796,983 |
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$ |
29,735,516 |
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Borrowing Base |
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$ |
50,000,000 |
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$ |
50,000,000 |
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Debt |
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$ |
29,500,000 |
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$ |
32,750,000 |
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Debt-to-Adjusted EBITDA (TTM) (2) |
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1.38 |
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1.45 |
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– 2 –
Operating Highlights
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Three Months Ended |
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Three Months Ended |
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Year Ended |
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Year Ended |
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Dec. 31, 2024 |
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Dec. 31, 2023 |
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Dec. 31, 2024 |
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Dec. 31, 2023 |
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Gas Mcf Sold |
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1,906,552 |
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1,775,577 |
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7,969,948 |
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7,457,084 |
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Average Sales Price per Mcf before the |
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effects of settled derivative contracts |
$ |
2.64 |
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$ |
2.53 |
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$ |
2.19 |
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$ |
2.61 |
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Average Sales Price per Mcf after the |
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effects of settled derivative contracts |
$ |
2.92 |
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$ |
2.76 |
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$ |
2.75 |
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$ |
2.96 |
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% of sales subject to hedges |
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46 |
% |
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44 |
% |
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47 |
% |
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46 |
% |
Oil Barrels Sold |
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43,571 |
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39,768 |
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178,357 |
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182,916 |
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Average Sales Price per Bbl before the |
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effects of settled derivative contracts |
$ |
69.82 |
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$ |
78.66 |
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$ |
74.59 |
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$ |
76.76 |
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Average Sales Price per Bbl after the |
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effects of settled derivative contracts |
$ |
69.50 |
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$ |
75.37 |
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$ |
73.49 |
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$ |
74.21 |
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% of sales subject to hedges |
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39 |
% |
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36 |
% |
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33 |
% |
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42 |
% |
NGL Barrels Sold |
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35,099 |
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38,422 |
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133,609 |
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137,484 |
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Average Sales Price per Bbl(1) |
$ |
23.01 |
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$ |
24.00 |
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$ |
21.95 |
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$ |
22.18 |
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Mcfe Sold |
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2,378,569 |
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2,244,717 |
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9,841,746 |
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9,379,484 |
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Natural gas, oil and NGL sales before the |
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effects of settled derivative contracts |
$ |
8,885,922 |
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$ |
8,548,783 |
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$ |
33,690,652 |
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$ |
36,536,285 |
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Natural gas, oil and NGL sales after the |
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effects of settled derivative contracts |
$ |
9,397,454 |
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$ |
8,823,534 |
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$ |
37,988,255 |
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$ |
38,719,598 |
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(1) There were no NGL settled derivative contracts during the 2024 and 2023 periods. |
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Total Production for the last four quarters was as follows:
Quarter ended |
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Mcf Sold |
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Oil Bbls Sold |
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NGL Bbls Sold |
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Mcfe Sold |
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12/31/2024 |
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1,906,552 |
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43,571 |
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35,099 |
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2,378,569 |
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9/30/2024 |
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1,898,442 |
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45,698 |
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34,332 |
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2,378,622 |
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6/30/2024 |
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2,464,846 |
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51,828 |
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31,994 |
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2,967,779 |
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3/31/2024 |
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1,700,108 |
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37,260 |
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32,184 |
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2,116,776 |
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The percentage of total production volumes attributable to natural gas was 80% for the quarter ended Dec. 31, 2024.
Royalty Interest Production for the last four quarters was as follows:
Quarter ended |
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Mcf Sold |
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Oil Bbls Sold |
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NGL Bbls Sold |
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Mcfe Sold |
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12/31/2024 |
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1,728,225 |
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39,592 |
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21,778 |
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2,096,435 |
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9/30/2024 |
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1,724,635 |
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41,170 |
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21,011 |
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2,097,722 |
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6/30/2024 |
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2,304,176 |
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47,024 |
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20,461 |
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2,709,090 |
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3/31/2024 |
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1,533,580 |
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33,083 |
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20,844 |
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1,857,147 |
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The percentage of royalty production volumes attributable to natural gas was 82% for the quarter ended Dec. 31, 2024.
– 3 –
Working Interest Production for the last four quarters was as follows:
Quarter ended |
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Mcf Sold |
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Oil Bbls Sold |
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NGL Bbls Sold |
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Mcfe Sold |
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12/31/2024 |
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178,327 |
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3,979 |
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13,321 |
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282,134 |
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9/30/2024 |
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173,807 |
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4,528 |
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13,321 |
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280,900 |
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6/30/2024 |
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160,670 |
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4,804 |
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11,533 |
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258,689 |
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3/31/2024 |
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166,528 |
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4,177 |
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11,340 |
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259,629 |
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Quarter Ended Dec. 31, 2024 Results
The Company recorded net income of $0.1 million, or $0.00 per diluted share, for the quarter ended Dec. 31, 2024, as compared to net income of $2.5 million, or $0.07 per diluted share, for the quarter ended Dec. 31, 2023. The change in net income was principally the result of an increase in losses associated with our derivative contracts, and an increase in depreciation, depletion and amortization (DD&A) expenses, partially offset by an increase in natural gas, oil, and NGL sales, a decrease in production and ad valorem taxes, a decrease in interest expense, and a decrease in general and administrative (G&A) expenses.
Natural gas, oil and NGL revenue increased $0.3 million, or 4%, for the quarter ended Dec. 31, 2024, compared to the quarter ended Dec. 31, 2023, due to an increase in natural gas and oil volumes of 7% and 10%, respectively, and an increase in natural gas prices of 4%, partially offset by decreases in oil, and NGL prices of 11%, and 4%, respectively, and a decrease in NGL volumes of 9%.
The increase in royalty production volumes during the quarter ended Dec. 31, 2024, as compared to the quarter ended Dec. 31, 2023, resulted primarily from new wells being brought online in the Haynesville Shale and SCOOP plays.
The Company had a net loss on derivative contracts of ($1.0) million for the quarter ended Dec. 31, 2024, comprised of a ($1.5) million unrealized non-cash loss on derivatives and a $0.5 million gain on settled derivatives, as compared to a net gain of $3.2 million for the quarter ended Dec. 31, 2023. The change in net loss on derivative contracts was due to the Company’s settlements of natural gas and oil collars and fixed price swaps and the change in valuation caused by the difference in Dec. 31, 2024 pricing relative to the strike price on open derivative contracts.
Year Ended Dec. 31, 2024 Results
The Company recorded net income of $2.3 million, or $0.06 per diluted share, for the year ended Dec. 31, 2024, as compared to a net income of $13.9 million, or $0.39 per diluted share, for the year ended Dec. 31, 2023. The change in net income was principally the result of a decrease in natural gas, oil and NGL sales, a decrease in gains associated with our derivative contracts, a decrease in gains on asset sales, an increase in transportation, gathering and marketing expenses, and an increase in depreciation, depletion and amortization expenses, partially offset by a decrease in the income tax provision.
Natural gas, oil and NGL revenue decreased $2.8 million, or 8%, for the year ended Dec. 31, 2024, compared to the year ended Dec. 31, 2023, due to a decreases in natural gas, oil, and NGL prices of 16%, 3%, and 1%, respectively, and decreases in oil and NGL volumes of 2% and 3%, respectively, partially offset by an increase in gas volumes of 7%.
The production increase in royalty volumes during the year ended Dec. 31, 2024, as compared to the year ended Dec. 31, 2023, resulted primarily from new wells in the Haynesville Shale and SCOOP plays coming online. The production decrease in working interest volumes during the year ended Dec. 31, 2024, as compared to the year ended Dec. 31, 2023, resulted from natural production decline and 2023 working interest divestitures.
The Company had a net gain on derivative contracts of $0.3 million for the year ended Dec. 31, 2024, comprised of a $4.3 million gain on settled derivatives and a $4.0 million non-cash loss on derivatives, as compared to a net gain of $6.9 million for the year ended Dec. 31, 2023. The change in net gain on derivative contracts was due to the Company’s settlements of natural gas and oil collars and fixed price swaps and the change in valuation caused by the difference in Dec. 31, 2024 pricing relative to the strike price on open derivative contracts.
Operations Update
During the quarter ended Dec. 31, 2024, the Company converted 71 gross (0.22 net) wells to producing status, including 21 gross (0.03 net) wells in the Haynesville and 43 gross (0.18 net) wells in the SCOOP, compared to 46 gross (0.10 net) wells converted in the quarter ended Dec. 31, 2023.
– 4 –
At Dec. 31, 2024, the Company had a total of 225 gross (0.91 net) wells in progress and permits across its mineral positions, compared to 278 gross (0.93 net) wells in progress and permits at Sept. 30, 2024. As of Feb. 3, 2025, 16 rigs were operating on the Company’s acreage and 62 rigs were operating within 2.5 miles of its acreage.
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Bakken/ |
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Three |
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Arkoma |
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SCOOP |
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STACK |
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Forks |
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Stack |
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Haynesville |
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Other |
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Total |
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As of Dec. 31, 2024: |
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Gross Wells in Progress on PHX Acreage (1) |
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58 |
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13 |
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5 |
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3 |
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63 |
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8 |
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150 |
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Net Wells in Progress on PHX Acreage (1) |
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0.194 |
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0.022 |
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0.006 |
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0.015 |
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0.320 |
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0.042 |
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0.599 |
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Gross Active Permits on PHX Acreage |
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28 |
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9 |
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8 |
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4 |
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23 |
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3 |
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75 |
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Net Active Permits on PHX Acreage |
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0.068 |
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0.083 |
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0.040 |
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0.030 |
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0.077 |
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0.014 |
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0.312 |
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As of Feb. 3, 2025: |
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|
|||||||
Rigs Present on PHX Acreage |
|
10 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
3 |
|
|
|
1 |
|
|
|
16 |
|
Rigs Within 2.5 Miles of PHX Acreage |
|
19 |
|
|
|
4 |
|
|
|
10 |
|
|
|
- |
|
|
|
13 |
|
|
|
16 |
|
|
|
62 |
|
(1) Wells in progress includes drilling wells and drilled but uncompleted wells, or DUCs.
Leasing Activity
During the quarter ended Dec. 31, 2024, the Company leased 265 net mineral acres to third-party exploration and production companies for an average bonus payment of $760 per net mineral acre and an average royalty of 23%.
Acquisition and Divestiture Update
During the quarter ended Dec. 31, 2024, the Company purchased 363 net royalty acres for approximately $2.5 million and had no significant divestitures.
|
|
Acquisitions |
|
|||||||||||
|
|
SCOOP |
|
|
Haynesville |
|
|
Other |
|
Total |
|
|||
During Three Months Ended Dec. 31, 2024: |
|
|
|
|
|
|
|
|
|
|
|
|||
Net Mineral Acres Purchased |
|
|
- |
|
|
|
222 |
|
|
- |
|
|
222 |
|
Net Royalty Acres Purchased |
|
|
- |
|
|
|
363 |
|
|
- |
|
|
363 |
|
Royalty Reserves Update
At Dec. 31, 2024, proved royalty reserves decreased 9% to 52.5 Bcfe compared to 57.8 Bcfe at Dec. 31, 2023. Proved developed royalty reserves increased by 0.1 Bcfe from Dec. 31, 2023 to Dec. 31, 2024 due to execution of our acquisition strategy and conversion of high interest undeveloped reserves to producing in the Haynesville and SCOOP. Proved undeveloped royalty reserves decreased by 5.4 Bcfe from Dec. 31, 2023 to Dec. 31, 2024 primarily due to transfers to proved developed royalty reserves, and those transferred proved undeveloped royalty reserves were not replaced due to reduced permitting activity in the Haynesville shale as a result of lower gas prices.
– 5 –
|
Proved Royalty Interest |
|
|||||
|
Reserves SEC Pricing |
|
|||||
|
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
||
Proved Developed Reserves: |
|
|
|||||
Mcf of Gas |
|
35,404,847 |
|
|
|
36,156,363 |
|
Barrels of Oil |
|
800,965 |
|
|
|
731,527 |
|
Barrels of NGL |
|
796,840 |
|
|
|
715,683 |
|
Mcfe (1) |
|
44,991,676 |
|
|
|
44,839,623 |
|
Proved Undeveloped Reserves: |
|
|
|
|
|
||
Mcf of Gas |
|
6,757,726 |
|
|
|
11,508,969 |
|
Barrels of Oil |
|
98,825 |
|
|
|
134,497 |
|
Barrels of NGL |
|
25,951 |
|
|
|
99,712 |
|
Mcfe (1) |
|
7,506,382 |
|
|
|
12,914,223 |
|
Total Proved Reserves: |
|
|
|
|
|
||
Mcf of Gas |
|
42,162,573 |
|
|
|
47,665,332 |
|
Barrels of Oil |
|
899,790 |
|
|
|
866,024 |
|
Barrels of NGL |
|
822,791 |
|
|
|
815,395 |
|
Mcfe (1) |
|
52,498,058 |
|
|
|
57,753,846 |
|
|
|
|
|
|
|
||
10% Discounted Estimated Future |
|
|
|
|
|
||
Net Cash Flows (before income taxes): |
|
|
|
|
|
||
Proved Developed |
$ |
60,879,737 |
|
|
$ |
73,448,070 |
|
Proved Undeveloped |
|
11,019,175 |
|
|
|
23,525,572 |
|
Total |
$ |
71,898,912 |
|
|
$ |
96,973,642 |
|
|
|
|
|
|
|
||
(1) Crude oil and NGL converted to natural gas on a one barrel of crude oil or NGL equals six Mcf of natural gas basis. |
|
||||||
Total Reserves Update
At Dec. 31, 2024, proved reserves were 63.7 Bcfe, as calculated by Cawley, Gillespie and Associates, Inc. (“CG&A”), the Company’s independent consulting petroleum engineering firm. This was an 11% decrease, compared to the 71.2 Bcfe of proved reserves at Dec. 31, 2023. Total proved developed reserves decreased 4% to 56.2 Bcfe, as compared to Dec. 31, 2023 reserve volumes, mainly due to pricing. SEC prices used for the Company’s Dec. 31, 2024 reserve report prepared by CG&A averaged $2.05 per Mcf for natural gas, $73.48 per barrel for oil and $20.97 per barrel for NGL, compared to $2.67 per Mcf for natural gas, $76.85 per barrel for oil and $21.98 per barrel for NGL for the Company’s Dec. 31, 2023 reserve report prepared by CG&A. These prices reflect net prices received at the wellhead.
– 6 –
|
Proved Reserves SEC Pricing |
|
|||||
|
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
||
Proved Developed Reserves: |
|
|
|||||
Mcf of Gas |
|
42,549,110 |
|
|
|
44,479,988 |
|
Barrels of Oil |
|
948,078 |
|
|
|
937,465 |
|
Barrels of NGL |
|
1,322,146 |
|
|
|
1,362,944 |
|
Mcfe (1) |
|
56,170,454 |
|
|
|
58,282,442 |
|
Proved Undeveloped Reserves: |
|
|
|
|
|
||
Mcf of Gas |
|
6,757,726 |
|
|
|
11,508,969 |
|
Barrels of Oil |
|
98,825 |
|
|
|
134,497 |
|
Barrels of NGL |
|
25,951 |
|
|
|
99,712 |
|
Mcfe (1) |
|
7,506,382 |
|
|
|
12,914,223 |
|
Total Proved Reserves: |
|
|
|
|
|
||
Mcf of Gas |
|
49,306,836 |
|
|
|
55,988,957 |
|
Barrels of Oil |
|
1,046,903 |
|
|
|
1,071,962 |
|
Barrels of NGL |
|
1,348,097 |
|
|
|
1,462,656 |
|
Mcfe (1) |
|
63,676,836 |
|
|
|
71,196,665 |
|
|
|
|
|
|
|
||
10% Discounted Estimated Future |
|
|
|
|
|
||
Net Cash Flows (before income taxes): |
|
|
|
|
|
||
Proved Developed |
$ |
68,623,088 |
|
|
$ |
86,694,012 |
|
Proved Undeveloped |
|
11,018,931 |
|
|
|
23,325,572 |
|
Total |
$ |
79,642,019 |
|
|
$ |
110,019,584 |
|
SEC Pricing |
|
|
|
|
|
||
Gas/Mcf |
$ |
2.05 |
|
|
$ |
2.67 |
|
Oil/Barrel |
$ |
73.48 |
|
|
$ |
76.85 |
|
NGL/Barrel |
$ |
20.97 |
|
|
$ |
21.98 |
|
|
|
|
|
|
|
||
Proved Reserves - Projected Future Pricing (2) |
|
||||||
|
|
|
|
|
|
||
10% Discounted Estimated Future |
Proved Reserves |
|
|||||
Net Cash Flows (before income taxes): |
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
||
Proved Developed |
$ |
109,165,292 |
|
|
$ |
107,635,503 |
|
Proved Undeveloped |
|
17,439,516 |
|
|
|
29,439,523 |
|
Total |
$ |
126,604,808 |
|
|
$ |
137,075,026 |
|
|
|
|
|
|
|
||
(1) Crude oil and NGL converted to natural gas on a one barrel of crude oil or NGL equals six Mcf of natural gas basis. |
|
||||||
(2) Projected futures pricing as of Dec. 31, 2024 and Dec. 31, 2023 basis adjusted to Company wellhead price. |
|
||||||
– 7 –
Quarterly Conference Call
PHX will host a conference call to discuss the Company’s results for the quarter ended Dec. 31, 2024 at 11 a.m. ET on Mar. 13, 2025. Management’s discussion will be followed by a question-and-answer session with investors.
To participate on the conference call, please dial 877-407-3088 (toll-free domestic) or 201-389-0927. A replay of the call will be available for 14 days after the call. The number to access the replay of the conference call is 877-660-6853 and the PIN for the replay is 13751358.
A live audio webcast of the conference call will be accessible from the “Investors” section of PHX’s website at https://phxmin.com/events. The webcast will be archived for at least 90 days.
FINANCIAL RESULTS
Statements of Income
|
Three Months Ended Dec. 31, |
|
|
Year Ended Dec. 31, |
|
|
||||||||||
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
|
||||
Revenues: |
|
|
|
|
|
|
|
|||||||||
Natural gas, oil and NGL sales |
$ |
8,885,922 |
|
|
$ |
8,548,783 |
|
|
$ |
33,690,652 |
|
|
$ |
36,536,285 |
|
|
Lease bonuses and rental income |
|
135,589 |
|
|
|
22,780 |
|
|
|
580,804 |
|
|
|
1,068,022 |
|
|
Gains (losses) on derivative contracts |
|
(998,129 |
) |
|
|
3,211,410 |
|
|
|
299,608 |
|
|
|
6,859,589 |
|
|
|
|
8,023,382 |
|
|
|
11,782,973 |
|
|
|
34,571,064 |
|
|
|
44,463,896 |
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Lease operating expenses |
|
307,330 |
|
|
|
319,113 |
|
|
|
1,228,813 |
|
|
|
1,598,944 |
|
|
Transportation, gathering and marketing |
|
1,017,501 |
|
|
|
945,788 |
|
|
|
4,513,381 |
|
|
|
3,674,832 |
|
|
Production and ad valorem taxes |
|
284,406 |
|
|
|
457,058 |
|
|
|
1,703,305 |
|
|
|
1,881,737 |
|
|
Depreciation, depletion and amortization |
|
2,605,809 |
|
|
|
2,443,154 |
|
|
|
9,606,444 |
|
|
|
8,566,185 |
|
|
Provision for impairment |
|
52,673 |
|
|
|
- |
|
|
|
52,673 |
|
|
|
38,533 |
|
|
Interest expense |
|
573,920 |
|
|
|
723,685 |
|
|
|
2,563,268 |
|
|
|
2,362,393 |
|
|
General and administrative |
|
2,905,229 |
|
|
|
3,050,828 |
|
|
|
11,670,328 |
|
|
|
11,970,182 |
|
|
Losses (gains) on asset sales and other |
|
194,665 |
|
|
|
84,443 |
|
|
|
83,799 |
|
|
|
(4,285,170 |
) |
|
Total costs and expenses |
|
7,941,533 |
|
|
|
8,024,069 |
|
|
|
31,422,011 |
|
|
|
25,807,636 |
|
|
Income (loss) before provision (benefit) for income taxes |
|
81,849 |
|
|
|
3,758,904 |
|
|
|
3,149,053 |
|
|
|
18,656,260 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Provision (benefit) for income taxes |
|
(27,551 |
) |
|
|
1,245,460 |
|
|
|
827,187 |
|
|
|
4,735,460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income (loss) |
$ |
109,400 |
|
|
$ |
2,513,444 |
|
|
$ |
2,321,866 |
|
|
$ |
13,920,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic earnings per common share |
$ |
0.00 |
|
|
$ |
0.07 |
|
|
$ |
0.06 |
|
|
$ |
0.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Diluted earnings per common share |
$ |
0.00 |
|
|
$ |
0.07 |
|
|
$ |
0.06 |
|
|
$ |
0.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Weighted average shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic |
|
36,398,660 |
|
|
|
36,036,270 |
|
|
|
36,329,735 |
|
|
|
35,980,309 |
|
|
Diluted |
|
36,944,330 |
|
|
|
36,083,449 |
|
|
|
36,412,270 |
|
|
|
35,980,309 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Dividends per share of |
|
|
|
|
|
|
|
|
|
|
|
|
||||
common stock paid in period |
$ |
0.0400 |
|
|
$ |
0.0300 |
|
|
$ |
0.1400 |
|
|
$ |
0.0975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
– 8 –
Balance Sheets
|
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
||
Assets |
|
|
|
|
|
||
Current assets: |
|
|
|
|
|
||
Cash and cash equivalents |
$ |
2,242,102 |
|
|
$ |
806,254 |
|
Natural gas, oil and NGL sales receivables (net of $0 |
|
6,128,954 |
|
|
|
4,900,126 |
|
allowance for uncollectable accounts) |
|
|
|
|
|
||
Refundable income taxes |
|
328,560 |
|
|
|
455,931 |
|
Derivative contracts, net |
|
- |
|
|
|
3,120,607 |
|
Other |
|
857,317 |
|
|
|
878,659 |
|
Total current assets |
|
9,556,933 |
|
|
|
10,161,577 |
|
|
|
|
|
|
|
||
Properties and equipment at cost, based on |
|
|
|
|
|
||
successful efforts accounting: |
|
|
|
|
|
||
Producing natural gas and oil properties |
|
223,043,942 |
|
|
|
209,082,847 |
|
Non-producing natural gas and oil properties |
|
51,806,911 |
|
|
|
58,820,445 |
|
Other |
|
1,361,064 |
|
|
|
1,360,614 |
|
|
|
276,211,917 |
|
|
|
269,263,906 |
|
Less accumulated depreciation, depletion and amortization |
|
(122,835,668 |
) |
|
|
(114,139,423 |
) |
Net properties and equipment |
|
153,376,249 |
|
|
|
155,124,483 |
|
|
|
|
|
|
|
||
Derivative contracts, net |
|
- |
|
|
|
162,980 |
|
Operating lease right-of-use assets |
|
429,494 |
|
|
|
572,610 |
|
Other, net |
|
553,090 |
|
|
|
486,630 |
|
Total assets |
$ |
163,915,766 |
|
|
$ |
166,508,280 |
|
|
|
|
|
|
|
||
Liabilities and Stockholders' Equity |
|
|
|
|
|
||
Current liabilities: |
|
|
|
|
|
||
Accounts payable |
$ |
804,693 |
|
|
$ |
562,607 |
|
Derivative contracts, net |
|
316,336 |
|
|
|
- |
|
Current portion of operating lease liability |
|
247,786 |
|
|
|
233,390 |
|
Accrued liabilities and other |
|
1,866,930 |
|
|
|
1,215,275 |
|
Total current liabilities |
|
3,235,745 |
|
|
|
2,011,272 |
|
|
|
|
|
|
|
||
Long-term debt |
|
29,500,000 |
|
|
|
32,750,000 |
|
Deferred income taxes, net |
|
7,286,315 |
|
|
|
6,757,637 |
|
Asset retirement obligations |
|
1,097,750 |
|
|
|
1,062,139 |
|
Derivative contracts, net |
|
398,072 |
|
|
|
- |
|
Operating lease liability, net of current portion |
|
448,031 |
|
|
|
695,818 |
|
Total liabilities |
|
41,965,913 |
|
|
|
43,276,866 |
|
|
|
|
|
|
|
||
Stockholders' equity: |
|
|
|
|
|
||
Common Stock, $0.01666 par value; 75,000,000 shares authorized and |
|
|
|
|
|
||
36,796,496 issued at Dec. 31, 2024; 54,000,500 shares authorized |
|
|
|
|
|
||
and 36,121,723 issued at Dec. 31, 2023 |
|
613,030 |
|
|
|
601,788 |
|
Capital in excess of par value |
|
44,029,492 |
|
|
|
41,676,417 |
|
Deferred directors' compensation |
|
1,323,760 |
|
|
|
1,487,590 |
|
Retained earnings |
|
77,073,332 |
|
|
|
80,022,839 |
|
|
|
123,039,614 |
|
|
|
123,788,634 |
|
Less treasury stock, at cost; 279,594 shares at Dec. 31, |
|
|
|
|
|
||
2024, and 131,477 shares at Dec. 31, 2023 |
|
(1,089,761 |
) |
|
|
(557,220 |
) |
Total stockholders' equity |
|
121,949,853 |
|
|
|
123,231,414 |
|
Total liabilities and stockholders' equity |
$ |
163,915,766 |
|
|
$ |
166,508,280 |
|
– 9 –
Condensed Statements of Cash Flows
|
Year Ended |
|
|||||
|
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
||
Operating Activities |
|
|
|
|
|
||
Net income |
$ |
2,321,866 |
|
|
$ |
13,920,800 |
|
Adjustments to reconcile net income (loss) to net cash provided |
|
|
|
|
|
||
by operating activities: |
|
|
|
|
|
||
Depreciation, depletion and amortization |
|
9,606,444 |
|
|
|
8,566,185 |
|
Impairment of producing properties |
|
52,673 |
|
|
|
38,533 |
|
Provision for deferred income taxes |
|
528,678 |
|
|
|
4,303,731 |
|
Gain from leasing fee mineral acreage |
|
(580,805 |
) |
|
|
(1,067,992 |
) |
Proceeds from leasing fee mineral acreage |
|
597,389 |
|
|
|
1,213,913 |
|
Net (gain) loss on sales of assets |
|
(518,816 |
) |
|
|
(4,728,758 |
) |
Directors' deferred compensation expense |
|
185,082 |
|
|
|
228,017 |
|
Total (gain) loss on derivative contracts |
|
(299,608 |
) |
|
|
(6,859,589 |
) |
Cash receipts (payments) on settled derivative contracts |
|
4,297,603 |
|
|
|
2,743,475 |
|
Restricted stock award expense |
|
2,287,927 |
|
|
|
2,205,910 |
|
Other |
|
98,104 |
|
|
|
136,412 |
|
Cash provided (used) by changes in assets and liabilities: |
|
|
|
|
|
||
Natural gas, oil and NGL sales receivables |
|
(1,228,828 |
) |
|
|
4,883,870 |
|
Income taxes receivable |
|
127,371 |
|
|
|
(455,931 |
) |
Other current assets |
|
(3,064 |
) |
|
|
(45,869 |
) |
Accounts payable |
|
252,386 |
|
|
|
69,228 |
|
Other non-current assets |
|
(22,985 |
) |
|
|
206,292 |
|
Income taxes payable |
|
- |
|
|
|
(576,427 |
) |
Accrued liabilities |
|
376,436 |
|
|
|
(610,661 |
) |
Total adjustments |
|
15,755,987 |
|
|
|
10,250,339 |
|
Net cash provided by operating activities |
|
18,077,853 |
|
|
|
24,171,139 |
|
|
|
|
|
|
|
||
Investing Activities |
|
|
|
|
|
||
Capital expenditures |
|
(87,579 |
) |
|
|
(325,983 |
) |
Acquisition of minerals and overriding royalty interests |
|
(7,796,983 |
) |
|
|
(29,735,516 |
) |
Net proceeds from sales of assets |
|
527,167 |
|
|
|
9,614,194 |
|
Net cash provided by (used in) investing activities |
|
(7,357,395 |
) |
|
|
(20,447,305 |
) |
|
|
|
|
|
|
||
Financing Activities |
|
|
|
|
|
||
Borrowings under credit facility |
|
3,000,000 |
|
|
|
19,500,000 |
|
Payments of loan principal |
|
(6,250,000 |
) |
|
|
(20,050,000 |
) |
Payments on off-market derivative contracts |
|
- |
|
|
|
(560,162 |
) |
Purchases of treasury stock |
|
(805,063 |
) |
|
|
(402,704 |
) |
Payments of dividends |
|
(5,229,547 |
) |
|
|
(3,520,366 |
) |
Net cash provided by (used in) financing activities |
|
(9,284,610 |
) |
|
|
(5,033,232 |
) |
|
|
|
|
|
|
||
Increase (decrease) in cash and cash equivalents |
|
1,435,848 |
|
|
|
(1,309,398 |
) |
Cash and cash equivalents at beginning of period |
|
806,254 |
|
|
|
2,115,652 |
|
Cash and cash equivalents at end of period |
$ |
2,242,102 |
|
|
$ |
806,254 |
|
|
|
|
|
|
|
||
Supplemental Disclosures of Cash Flow Information: |
|
|
|
|
|
||
|
|
|
|
|
|
||
Interest paid (net of capitalized interest) |
$ |
2,611,089 |
|
|
$ |
2,405,361 |
|
Income taxes paid (net of refunds received) |
$ |
318,789 |
|
|
$ |
1,464,087 |
|
|
|
|
|
|
|
||
Supplemental Schedule of Noncash Investing and Financing Activities: |
|
|
|
|
|
||
|
|
|
|
|
|
||
Dividends declared and unpaid |
$ |
155,271 |
|
|
$ |
113,443 |
|
|
|
|
|
|
|
||
Gross additions to properties and equipment |
$ |
7,893,036 |
|
|
$ |
30,761,578 |
|
Net increase (decrease) in accounts receivable for properties |
|
|
|
|
|
||
and equipment additions |
|
(8,474 |
) |
|
|
(700,079 |
) |
Capital expenditures and acquisitions |
$ |
7,884,562 |
|
|
$ |
30,061,499 |
|
– 10 –
Derivative Contracts as of Dec. 31, 2024
|
|
Production volume |
|
|
|
|
Contract period |
|
covered per month |
|
Index |
|
Contract price |
|
|
|
|
|
|
|
Natural gas costless collars |
|
|
|
|
|
|
January - June 2025 |
|
30,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.00 floor / $5.00 ceiling |
January - March 2025 |
|
90,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.25 floor / $5.25 ceiling |
January - March 2025 |
|
25,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.00 floor / $3.37 ceiling |
January - March 2025 |
|
30,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.50 floor / $5.15 ceiling |
January 2025 |
|
55,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.50 floor / $4.40 ceiling |
February 2025 |
|
25,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.50 floor / $4.40 ceiling |
March 2025 |
|
35,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.50 floor / $4.40 ceiling |
April 2025 - September 2025 |
|
55,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.00 floor / $3.75 ceiling |
November 2025 - March 2026 |
|
100,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.50 floor / $4.85 ceiling |
November 2025 - March 2026 |
|
75,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.50 floor / $4.72 ceiling |
November 2025 - March 2026 |
|
50,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.50 floor / $3.87 ceiling |
November 2025 - March 2026 |
|
15,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.50 floor / $5.15 ceiling |
April - June 2026 |
|
75,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.00 floor / $3.60 ceiling |
July - September 2026 |
|
100,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.00 floor / $3.60 ceiling |
Natural gas fixed price swaps |
|
|
|
|
|
|
January - March 2025 |
|
60,000 Mmbtu |
|
NYMEX Henry Hub |
|
$4.16 |
January - March 2025 |
|
50,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.51 |
April - May 2025 |
|
25,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.23 |
April - August 2025 |
|
125,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.01 |
April - October 2025 |
|
100,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.28 |
June 2025 |
|
10,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.23 |
July 2025 |
|
45,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.23 |
August 2025 |
|
40,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.23 |
September 2025 |
|
50,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.23 |
September - October 2025 |
|
100,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.01 |
October 2025 |
|
100,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.23 |
November - January 2026 |
|
25,000 Mmbtu |
|
NYMEX Henry Hub |
|
$4.21 |
February 2026 |
|
15,000 Mmbtu |
|
NYMEX Henry Hub |
|
$4.21 |
March 2026 |
|
25,000 Mmbtu |
|
NYMEX Henry Hub |
|
$4.21 |
April - June 2026 |
|
50,000 Mmbtu |
|
NYMEX Henry Hub |
|
$3.10 |
Oil costless collars |
|
|
|
|
|
|
December 2024 |
|
500 Bbls |
|
NYMEX WTI |
|
$67.00 floor / $77.00 ceiling |
– 11 –
Oil fixed price swaps |
|
|
|
|
|
|
December 2024 - August 2025 |
|
1,000 Bbls |
|
NYMEX WTI |
|
$68.80 |
December 2024 - March 2025 |
|
1,600 Bbls |
|
NYMEX WTI |
|
$64.80 |
December 2024 |
|
500 Bbls |
|
NYMEX WTI |
|
$74.94 |
December 2024 |
|
2,000 Bbls |
|
NYMEX WTI |
|
$69.50 |
January 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$74.48 |
January - March 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$69.50 |
January - June 2025 |
|
2,000 Bbls |
|
NYMEX WTI |
|
$70.90 |
February 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$74.10 |
March 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$73.71 |
April 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$73.30 |
April - June 2025 |
|
750 Bbls |
|
NYMEX WTI |
|
$69.50 |
April - June 2025 |
|
1,000 Bbls |
|
NYMEX WTI |
|
$68.00 |
May 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$72.92 |
June 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$72.58 |
July 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$72.24 |
July - August 2025 |
|
1,250 Bbls |
|
NYMEX WTI |
|
$70.81 |
July - September 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$69.50 |
July - December 2025 |
|
1,500 Bbls |
|
NYMEX WTI |
|
$68.90 |
August 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$71.88 |
September 2025 |
|
500 Bbls |
|
NYMEX WTI |
|
$71.60 |
September 2025 |
|
1,500 Bbls |
|
NYMEX WTI |
|
$68.80 |
October 2025 |
|
750 Bbls |
|
NYMEX WTI |
|
$71.12 |
October 2025 |
|
2,000 Bbls |
|
NYMEX WTI |
|
$68.80 |
November 2025 |
|
750 Bbls |
|
NYMEX WTI |
|
$70.99 |
November 2025 - March 2026 |
|
1,500 Bbls |
|
NYMEX WTI |
|
$68.80 |
December 2025 |
|
750 Bbls |
|
NYMEX WTI |
|
$70.66 |
January 2026 |
|
1,500 Bbls |
|
NYMEX WTI |
|
$70.53 |
February 2026 |
|
1,500 Bbls |
|
NYMEX WTI |
|
$71.28 |
March 2026 |
|
1,500 Bbls |
|
NYMEX WTI |
|
$70.42 |
April - June 2026 |
|
1,000 Bbls |
|
NYMEX WTI |
|
$68.80 |
April - June 2026 |
|
1,000 Bbls |
|
NYMEX WTI |
|
$65.80 |
Non-GAAP Reconciliation
This press release includes certain “non-GAAP financial measures” as defined under the rules and regulations of the U.S. Securities and Exchange Commission, or the SEC, including Regulation G. These non-GAAP financial measures are calculated using GAAP amounts in the Company’s financial statements. These measures, detailed below, are provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in the Company’s financial statements prepared in accordance with GAAP (including the notes thereto), included in the Company’s SEC filings and posted on its website.
Adjusted EBITDA Reconciliation
The Company defines “adjusted EBITDA” as earnings before interest, taxes, depreciation and amortization, or EBITDA, excluding non-cash gains (losses) on derivatives and gains (losses) on asset sales and including cash receipts from (payments on) off-market derivatives and restricted stock and deferred directors’ expense. The Company has included a presentation of adjusted EBITDA because it recognizes that certain investors consider this amount to be a useful means of measuring the Company’s ability to meet its debt service obligations and evaluating its financial performance. Adjusted EBITDA has limitations and should not be considered in isolation or as a substitute for net income, operating income, cash flow from operations or other consolidated income or cash flow data prepared in accordance with GAAP. Because not all companies use identical calculations, this presentation of adjusted EBITDA may not be comparable to a similarly titled measure of other companies.
– 12 –
The following table provides a reconciliation of net income (loss) to adjusted EBITDA for the quarters indicated:
|
Three Months Ended |
|
|
Three Months Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Three Months Ended |
|
|||||
|
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
|
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
|
Sept. 30, 2024 |
|
|||||
Net Income |
$ |
109,400 |
|
|
$ |
2,513,444 |
|
|
$ |
2,321,866 |
|
|
$ |
13,920,800 |
|
|
$ |
1,100,310 |
|
Plus: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Income tax expense |
|
(27,551 |
) |
|
|
1,245,460 |
|
|
|
827,187 |
|
|
|
4,735,460 |
|
|
|
457,255 |
|
Interest expense |
|
573,920 |
|
|
|
723,685 |
|
|
|
2,563,268 |
|
|
|
2,362,393 |
|
|
|
622,480 |
|
DD&A |
|
2,605,809 |
|
|
|
2,443,154 |
|
|
|
9,606,444 |
|
|
|
8,566,185 |
|
|
|
2,376,025 |
|
Impairment expense |
|
52,673 |
|
|
|
- |
|
|
|
52,673 |
|
|
|
38,533 |
|
|
|
- |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Non-cash gains (losses) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
on derivatives |
|
(1,509,661 |
) |
|
|
2,936,659 |
|
|
|
(3,997,995 |
) |
|
|
4,302,531 |
|
|
|
157,086 |
|
Gains (losses) on asset sales |
|
- |
|
|
|
57,505 |
|
|
|
518,391 |
|
|
|
4,728,759 |
|
|
|
6,708 |
|
Plus: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Cash payments on off-market |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
derivative contracts |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(373,745 |
) |
|
|
- |
|
Restricted stock and deferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
director's expense |
|
561,603 |
|
|
|
572,709 |
|
|
|
2,473,008 |
|
|
|
2,433,927 |
|
|
|
513,059 |
|
Adjusted EBITDA |
$ |
5,385,515 |
|
|
$ |
4,504,288 |
|
|
$ |
21,324,050 |
|
|
$ |
22,652,263 |
|
|
$ |
4,905,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Adjusted Pretax Net Income (Loss) Reconciliation
“Adjusted pretax net income (loss)” is defined as earnings before taxes, excluding non-cash gains (losses) on derivatives. The Company has included a presentation of adjusted pretax net income (loss) because it recognizes that certain investors consider this amount to be a useful means of measuring the Company’s ability to meet its debt service obligations and evaluating its financial performance. Adjusted pretax net income (loss) has limitations and should not be considered in isolation or as a substitute for net income, operating income, cash flow from operations or other consolidated income or cash flow data prepared in accordance with GAAP. Because not all companies use identical calculations, this presentation of adjusted pretax net income (loss) may not be comparable to a similarly titled measure of other companies. The following table provides a reconciliation of net income (loss) to adjusted pretax net income (loss) for the periods indicated:
– 13 –
|
Three Months Ended |
|
|
Twelve Months Ended |
|
|
Twelve Months Ended |
|
|
Three Months Ended |
|
||||
|
Dec. 31, 2024 |
|
|
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
|
Sept. 30, 2024 |
|
||||
Net Income (Loss) |
$ |
109,400 |
|
|
$ |
2,321,866 |
|
|
$ |
13,920,800 |
|
|
$ |
1,100,310 |
|
Plus: |
|
|
|
|
|
|
|
|
|
|
|
||||
Income tax expense (benefit) |
|
(27,551 |
) |
|
|
827,187 |
|
|
|
4,735,460 |
|
|
|
457,255 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
||||
Non-cash gains (losses) |
|
|
|
|
|
|
|
|
|
|
|
||||
on derivatives |
|
(1,509,661 |
) |
|
|
(3,997,995 |
) |
|
|
4,302,531 |
|
|
|
157,086 |
|
Adjusted Pretax Net Income (Loss) |
$ |
1,591,510 |
|
|
$ |
7,147,048 |
|
|
$ |
14,353,729 |
|
|
$ |
1,400,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Weighted average shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
||||
Basic |
|
36,398,660 |
|
|
|
36,329,735 |
|
|
|
35,980,309 |
|
|
|
36,316,742 |
|
Diluted |
|
36,944,330 |
|
|
|
36,412,270 |
|
|
|
35,980,309 |
|
|
|
36,983,669 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Adjusted Pretax Net Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
||||
per basic share |
$ |
0.04 |
|
|
$ |
0.20 |
|
|
$ |
0.40 |
|
|
$ |
0.04 |
|
Adjusted Pretax Net Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
||||
per diluted share |
$ |
0.04 |
|
|
$ |
0.20 |
|
|
$ |
0.40 |
|
|
$ |
0.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Debt-to-Adjusted EBITDA (TTM) Reconciliation
“Debt-to-adjusted EBITDA (TTM)” is defined as the ratio of long-term debt to adjusted EBITDA on a trailing 12-month (TTM) basis. The Company has included a presentation of debt-to-adjusted EBITDA (TTM) because it recognizes that certain investors consider such ratios to be a useful means of measuring the Company’s ability to meet its debt service obligations and for evaluating its financial performance. The debt-to-adjusted EBITDA (TTM) ratio has limitations and should not be considered in isolation or as a substitute for net income, operating income, cash flow from operations or other consolidated income or cash flow data prepared in accordance with GAAP. Because not all companies use identical calculations, this presentation of debt-to-adjusted EBITDA (TTM) may not be comparable to a similarly titled measure of other companies. The following table provides a reconciliation of net income (loss) to adjusted EBITDA on a TTM basis and of the resulting debt-to-adjusted EBITDA (TTM) ratio:
– 14 –
|
TTM Ended |
|
|
TTM Ended |
|
||
|
Dec. 31, 2024 |
|
|
Dec. 31, 2023 |
|
||
Net Income |
$ |
2,321,866 |
|
|
$ |
13,920,800 |
|
Plus: |
|
|
|
|
|
||
Income tax expense |
|
827,187 |
|
|
|
4,735,460 |
|
Interest expense |
|
2,563,268 |
|
|
|
2,362,393 |
|
DD&A |
|
9,606,444 |
|
|
|
8,566,185 |
|
Impairment expense |
|
52,673 |
|
|
|
38,533 |
|
Less: |
|
|
|
|
|
||
Non-cash gains (losses) |
|
|
|
|
|
||
on derivatives |
|
(3,997,995 |
) |
|
|
4,302,531 |
|
Gains (losses) on asset sales |
|
518,391 |
|
|
|
4,728,759 |
|
Plus: |
|
|
|
|
|
||
Cash payments on off-market derivative |
|
|
|
|
|
||
contracts |
|
- |
|
|
|
(373,745 |
) |
Restricted stock and deferred |
|
|
|
|
|
||
director's expense |
|
2,473,008 |
|
|
|
2,433,927 |
|
Adjusted EBITDA |
$ |
21,324,050 |
|
|
$ |
22,652,263 |
|
|
|
|
|
|
|
||
Debt |
$ |
29,500,000 |
|
|
$ |
32,750,000 |
|
Debt-to-Adjusted EBITDA (TTM) |
|
1.38 |
|
|
|
1.45 |
|
|
|
|
|
|
|
||
PHX Minerals Inc. Fort Worth-based, PHX Minerals Inc. is a natural gas and oil mineral company with a strategy to proactively grow its mineral position in its core focus areas. PHX owns mineral acreage principally located in Oklahoma, Texas, Louisiana, North Dakota and Arkansas. Additional information about the Company can be found at www.phxmin.com.
– 15 –
Cautionary Statement Regarding Forward-Looking Statements
This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Words such as “anticipates,” “plans,” “estimates,” “believes,” “expects,” “intends,” “will,” “should,” “may” and similar expressions may be used to identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect PHX’s current views about future events. Forward-looking statements may include, but are not limited to, statements relating to: the Company’s operational outlook; the Company’s ability to execute its business strategies; the volatility of realized natural gas and oil prices; the level of production on the Company’s properties; estimates of quantities of natural gas, oil and NGL reserves and their values; general economic or industry conditions; legislation or regulatory requirements; conditions of the securities markets; the Company’s ability to raise capital; changes in accounting principles, policies or guidelines; financial or political instability; acts of war or terrorism; title defects in the properties in which the Company invests; and other economic, competitive, governmental, regulatory or technical factors affecting properties, operations or prices. Although the Company believes expectations reflected in these and other forward-looking statements are reasonable, the Company can give no assurance such expectations will prove to be correct. Such forward-looking statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. These forward-looking statements involve certain risks and uncertainties that could cause results to differ materially from those expected by the Company’s management. Information concerning these risks and other factors can be found in the Company’s filings with the SEC, including its Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on the Company’s website or the SEC’s website at www.sec.gov.
Investors are cautioned that any such forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those projected. The forward-looking statements in this press release are made as of the date hereof, and the Company does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise.
Investor Contact:
Rob Fink / Stephen Lee
FNK IR
646.809.4048
PHX@fnkir.com
Corporate Contact:
405.948.1560
inquiry@phxmin.com
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Investor Presentation March 2025 Exhibit 99.2 NYSE: PHX
This presentation is for informational purposes only. This presentation does not constitute an offer to sell, a solicitation of an offer to buy, or a recommendation to purchase any security of PHX Minerals Inc. (“PHX” or the “Company”). No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, or an exemption therefrom. Cautionary Statement Regarding Forward-Looking Statements This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that the company expects, believes or anticipates will or may occur in the future are forward looking statements. The words “anticipates”, “plans”, “estimates”, “believes”, “expects”, “intends”, “will”, “should”, “may”, “goal”, “forecast”, “target”, and similar expressions may be used to identify forward-looking statements. Forward-looking statements may include, but are not limited to, statements regarding estimates of quantities of natural gas, oil and NGL reserves and their values and forecasts of financial and performance metrics. Although the Company believes the expectations reflected in these forward-looking statements are reasonable, the Company can give no assurance such statements will prove to be correct. Such forward-looking statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. Particular risks and uncertainties that could cause our results to differ materially from those expected by the Company’s management include, but are not limited to: our ability to execute our business strategies; the volatility of realized natural gas and oil prices; the level of production on our properties; estimates of quantities of natural gas, oil and NGL reserves and their values; general economic or industry conditions; legislation or regulatory requirements; conditions of the securities markets; our ability to raise capital; changes in accounting principles, policies or guidelines; financial or political instability; acts of war or terrorism; title defects in the properties in which we invest; and other economic, competitive, governmental, regulatory or technical factors affecting our properties, operations or prices. Information concerning these risks and other factors can be found in the Company’s filings with the Securities and Exchange Commission, including its Annual Report on Form 10-K and Quarterly Reports on Form 10-Q, available on the Company's website or the SEC’s website at www.sec.gov. Readers are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this presentation are made as of the date hereof, and the Company does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise. Use of Non-GAAP Financial Information This presentation includes certain non-GAAP financial measures. Adjusted EBITDA is a supplemental non-GAAP measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. PHX defines “Adjusted EBITDA” as earnings before interest, taxes, depreciation and amortization, or EBITDA, excluding non-cash gains (losses) on derivatives and gains (losses) on asset sales, impairment expense, and restricted stock and deferred directors’ expense, and including cash receipts from (payments on) off-market derivatives. PHX references Adjusted EBITDA in this presentation because it recognizes that certain investors consider Adjusted EBITDA a useful means of measuring our ability to meet our debt service obligations and evaluating our financial performance. Adjusted EBITDA has limitations and should not be considered in isolation or as a substitute for net income, operating income, cash flow from operations or other consolidated income or cash flow data prepared in accordance with GAAP. Because not all companies use identical calculations, the Company’s calculations of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Oil and Gas Reserves The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. The Company discloses only estimated proved reserves in its filings with the SEC. The Company’s estimated proved reserves as of December 31, 2024, referenced in this presentation were prepared by Cawley, Gillespie and Associates, Inc, an independent engineering firm, and comply with definitions promulgated by the SEC. Additional information on the Company’s estimated proved reserves is contained in the Company’s filings with the SEC, including its Annual Report on Form 10-K. Cautionary Statement Regarding Forward-Looking Statements
Source: Company information and Enverus 1 Based on $4.00 per share as of 12/31/2024 and 37.9 million shares outstanding on a fully diluted basis as of 12/31/2024 2 Market Cap plus debt of $29.5 million minus cash on hand of $2.2 million as of 12/31/2024 3 Calculated as working capital (current assets less current liabilities excluding current derivatives) plus availability on the borrowing base. See Non-GAAP reconciliation in Appendix 4 Based on $0.16 annualized Dividend per share 5 Total Debt / TTM Adjusted EBITDA; See Non-GAAP Reconciliation in Appendix 6 See Non-GAAP reconciliation in Appendix 7 3P Reserves per 12/31/2024 CGA at 12/31/2024 SEC price deck of $73.48 per bbl of oil, $20.97 per bbl of NGL, $2.05 per mcf of gas (proved volume weighted average price) 8 As of 12/31/2024; average royalty rate of ~16%; PHX also owns 168,966 unleased net mineral acres. This does not reflect the divestiture of 165,326 non-producing acres for ~$8 million on 1/31/2025 or the acquisition of 50 net royalty acres for ~$0.6 million on 1/2/2025 9 At mid-point of production outlook (see page 10) 10 Since 12/31/2024, the Company has paid down $9.8 million of debt, bringing the debt balance to $19.8 million as of Mar. 5, 2025. Company Snapshot Key Statistics Market Cap1 $151.7 Enterprise Value2,10 $179.0 Liquidity3,10 $27.1 Dividend Yield4 4.0% Leverage5,10 1.38x LTM Adjusted EBITDA6 $21.3 LTM Discretionary Cash Flow Yield6 ~12% LTM ROCE6 ~8% Percent of 3P Reserves – Natural Gas7 ~70% Net Leased Royalty Acres8 89,135 Sustainable Organic Royalty Production Growth MMCFE 3 $ in millions CAGR: ~28%
Strategy Execution Goals Set in early 2020 Achievements Through Dec. 31, 2024 High Grade Asset Base Grow royalty production Increase inventory of undeveloped locations Improve operating margins Exit working interest assets Royalty production volumes up ~278% 2P royalty reserves up ~130% Completed ~$139 million1 in mineral acquisitions Built a 10+ year inventory of mineral locations with line-of-sight to development and conversion to cash flow Increased discretionary cash flow margin from 36% to 56% Divested ownership in 1,380 working interest wellbores Build a strong and sustainable balance sheet Maintained leverage ratio between 1.0x and 1.5x compared to over 2.5x in 2020 Entered into a new and improved commercial bank relationship Become a consolidator in the mineral space Allocate capital to generate the best possible returns to shareholders Mineral acquisitions completed: 911 Focus on smaller acquisition in targeted areas: ~$1.5 million average1 deal size generates higher returns with less competition Generate return on capital employed (ROCE) Generated annual ROCE2 between 7% and 15% since 2021; up from ~0% in 2019 and 2020 Return profile driven by royalty volume growth associated with new wells converting from undeveloped locations Improve balance sheet designed to withstand commodity price volatility 1 This does not reflect PHX’s most recent acquisition of 50 net royalty acres for ~$0.6 million on 1/2/2025 2 See Non-GAAP reconciliation in Appendix
Focused in SCOOP and Haynesville Key Operators of PHX Minerals Source: Company info and Enverus 1 Rig data from Enverus as of 12/31/2024 PHX targets areas in key plays with significant active operator development activity Provides line of sight to conversion of undeveloped locations to cash flow
Royalty Cash Flow Driving Shareholder Value Royalty Production and Realized Natural Gas Price Adjusted EBITDA1 Discretionary Cash Flow Margin2 Return on Capital Employed3 $ in millions Source: Company filings ; All quarters are in Calendar Year 1 Calculated as net income excluding non-cash gain/loss on derivatives, income tax expense, interest expense, DD&A, non-cash impairments, non-cash G&A, gain(losses) on asset sales and cash receipts from/payments on off-market derivatives; See Non-GAAP reconciliation in Appendix 2 Calculated as Adjusted EBITDA minus interest expense divided by total oil and gas sales 3 See Non-GAAP reconciliation in Appendix
Stable Balance Sheet & Ample Liquidity Net Debt 1 Percentage Drawn on Credit Facility Advance Rate Debt / Adjusted EBITDA2 (TTM) Liquidity3 $ in millions $ in millions Source: Company filings ; All quarters are in Calendar Year 1 Total debt less cash 2 Total Debt / Adjusted EBITDA; See Non-GAAP reconciliation in Appendix 3 Calculated as working capital (current assets less current liabilities excluding current derivatives) plus availability on the borrowing base; See Non-GAAP reconciliation in Appendix 4 Since 12/31/2024, the Company has paid down $9.8 million of debt, bringing the debt balance to $19.8 million as of Mar. 5, 2025.
Royalty Reserve Growth Sustainable royalty reserve and production growth through conversion of existing mineral location inventory Royalty Reserves Royalty Production MMCFE CAGR: ~23% MMCFE CAGR: ~28%
Yearly Conversions To Producing Wells Strong drilling activity on our mineral assets provides sustainable annual royalty production growth Gross Conversions Net Conversions
Quarterly Near-Term Drilling Inventory Continuous conversion of undrilled location inventory will drive future royalty volume growth Gross Inventory Net Inventory
Royalty Interest Inventory by Basin Sub-region Gross PDP Wells1,6 Net PDP Wells1,3,6 Undeveloped Locations1 Sub-region PDP Wells Average NRI1 Gross Wells In Progress2 Net Wells in Progress3 Gross Permits Net Permits3 Gross Technical PUDs4 Net Technical PUDs3,4,5 Gross PROB Net PROB3,5 Gross POSS Net POSS3,5 SCOOP 1,255 4.985 58 0.194 28 0.068 380 1.011 719 1.981 1,146 4.021 Haynesville 712 4.016 63 0.320 23 0.077 160 0.487 273 1.031 34 0.075 STACK 411 1.752 13 0.022 9 0.083 197 0.723 242 0.747 126 0.402 Bakken 634 1.858 5 0.006 8 0.040 71 0.143 136 0.478 3 0.045 Arkoma Stack 504 4.523 3 0.015 4 0.030 112 0.477 96 0.235 135 0.352 Fayetteville 1,070 6.438 0 0.000 0 0.000 0 0.00 0.00 0.00 0.00 0.00 Other 1,983 15.988 8 0.042 3 0.014 32 0.00 30 0.180 16 0.00 Total 6,569 39.560 150 0.599 75 0.312 952 2.976 1,496 4.652 1,460 4.964 Gross Undeveloped Locations 4,133 4,133 Note: 1 As of 12/31/2024 2 Wells in Progress includes wells currently being drilled and wells waiting on completion 3 Net interest on wells are internal estimates and subject to confirmation from operator 4 Technical PUDs, reviewed and approved by Cawley, Gillespie and Associates, Inc., share all technical merits of PUDs but development timing is uncertain. PHX Technical PUDs are most likely PUDs in their respective operator’s reserve report. 5 Technical PUDs, PROB, and POSS net wells assume 10,000 ft. laterals 6 This does not reflect PHX’s most recent acquisition of 50 net royalty acres for ~$0.6 million on 1/2/2025 2 Continuous conversion of undrilled location inventory will drive future royalty volume growth
Analyst Coverage Firm Analyst Contact Johnson Rice Charles Meade cmeade@jrco.com Alliance Global Partners Jeff Grampp jgrampp@allianceg.com Texas Capital Derrick Whitfield derrick.whitfield@texascapital.com
Appendix
Company Leadership Management Team Title Years with Company Experience Chad Stephens President, CEO and Board Director 6 CEO for PHX since 2019 SVP –Corporate Development of Range Resources for 30 years until retiring in 2018 B.A. in Finance and Land Management from University of Texas Ralph D’Amico Executive Vice President, CFO 6 CFO for PHX since 2020 20 years of investment banking experience Bachelor’s in Finance from University of Maryland; MBA from George Washington University Chad True S.V.P. of Accounting 5 >17 years of accounting experience Audit and accounting positions with Grant Thornton LP, Tiptop Oil & Gas and Wexford Capital LP B.S. and Masters in Accounting from Oklahoma State University Danielle Mezo V.P. of Engineering 5 >15 years reservoir engineer experience Reservoir engineer, acquisitions, and corporate planning positions at SandRidge Energy B.S. in Petroleum Engineering from University of Oklahoma and licensed Professional Engineer Kenna Clapp V.P. of Land 5 >15 years of land experience Various land positions with Chesapeake Energy in Haynesville, Eagleford, Mid-Continent and Barnett shales B.S. in Accounting and Finance from Oklahoma State University; JD from Oklahoma City University Taylor McClain V.P. of Geology 1 >10 years of experience across multiple basins including Appalachia, Haynesville, Permian and Mid-Continent Various exploration and production Geologist positions with Range Resources, UBS and Redfield Energy B.S. in Geoscience from Pennsylvania State University and a Masters in Geology from West Virginia University Board of Directors Title Years with Company Experience Mark T. Behrman Chairman 8 CEO of LSB Industries, Inc. since 2018 and Chairman of LSB Industries, Inc. since August of 2024 Managing Director and Head of Investment Banking of the Industrial and Energy Practices of Sterne Agee from 2007 to 2014 MBA in Finance from Hofstra University and B.S. in Accounting, Minor in Finance from Binghamton University Glen A. Brown Director 4 SVP – Exploration for Continental Resources from 2015 through 2017 Exploration manager for EOG Resources Midcontinent from 1991 through 2003 Bachelor’s in Geology from State University of New York; Master’s in Geology from New Mexico State University in Las Cruces Lee M. Canaan Director 9 Founder and portfolio manager of Braeburn Capital Partners, LLC Board member for EQT Corporation and Aethon Energy, LLC Bachelor’s in Geological Sciences from USC, Master’s in Geophysics from UT-Austin, and MBA in Finance from Wharton Steven L. Packebush Director 3 Founder and partner in Elevar Partners, LLC President of Koch Ag & Energy Solutions upon his retirement in 2018 after 30 years with the company Bachelor’s in agricultural economics from Kansas State John H. Pinkerton Director 4 CEO of Range Resources Corporation from 1992 through 2012 Executive Chairman and Chairman of Board of Directors for Encino Energy from 2017 through 2022 B.A. in Business Administration from Texas Christian University; Master’s from the University of Texas at Arlington
Scoop Haynesville Bakken Stack Arkoma Fayetteville Other Total Production Mix Net Production (MMcfe/d)1,3 4.16 14.19 1.20 2.97 1.08 0.88 2.47 26.96 Leased Net Royalty Acres2 9,615 8,979 4,026 6,691 9,839 8,394 41,591 89,135 Permits on File1 28 23 8 9 4 - 3 75 Rigs Running on PHX Acreage4 6 4 2 0 - - 1 13 Rigs Running Within 2.5 miles of PHX Acreage4 18 10 16 4 - - 12 60 Key Operators 1 As of 12/31/2024 2 As of 12/31/2024; average royalty rate of ~16%; PHX also owns 168,966 unleased net mineral acres. This does not reflect the divestiture of 165,326 non-producing acres for ~$8 million on 1/31/2025 or the acquisition of 50 net royalty acres for ~$0.6 million on 1/2/2025 3 Includes both royalty and working interest production 4 Rig data from Enverus as of 12/31/2024 Portfolio Overview by Basin 29%
TRINITY | BYRD 23-26-35 | 3 WELL AVG 1st Prod 3/2024 PHX NRI 0.410% LL 10,450’ IP24hr 18.2 MMCFPD NRM PROP 4,200 #/FT IP30 12.5 MMCFPD CHESAPEAKE | ARK 9&16&21-15-16HC 001 1st Prod 1/2024 PHX NRI 0.563% LL 12,500’ IP24hr 30.7 MMCFPD NRM PROP 3,900 #/FT IP30 25.9 MMCFPD Texas / Louisiana Haynesville Update Notable Well Results5 CHESAPEAKE | L 14-23-26-35 HC 001 1st Prod 3/2024 PHX NRI 0.416% LL 10,450’ IP24hr 39.5 MMCFPD NRM PROP 4,200 #/FT IP30 32.2 MMCFPD AETHON | BURNS FOREST / MOJO MINERALS DSU | 5 WELL AVG 1st Prod 1/2024 PHX NRI 4.671% LL 9,800’ IP24hr 21.8 MMCFPD NRM PROP 4,700 #/FT IP30 11.7 MMCFPD Source: Company info and Enverus 1 As of 12/31/2024 2 Wells in Progress includes wells currently being drilled and wells waiting on completion 3 Active natural gas and oil horizontal permits filed 4 Rig data from Enverus as of 12/31/2024 5 NRIs are internal estimates and are subject to confirmation from operator Operators are drilling 3-5 wells per unit, and a positive indication of near term volumes and cashflows Since 2019, core development areas have been extended as new completion designs have lowered breakevens Key Operators: Aethon, Trinity, Chesapeake, Silverhill, Blue Dome and Paloma PHX TX / LA AOI Haynesville Ownership1: 7,874 NRA (total PHX Haynesville ownership 8,979 NRA) Gross Wells In Progress on PHX1,2: 55 (total PHX Haynesville gross active WIPs 63) Gross Active Permits on PHX1,3: 23 (total PHX Haynesville gross active permits 23) Total Active Rigs in TX / LA AOI4: 21 1 2 3 4 1 2 4 3
AETHON | ATTOYAC RIVER GAS UNIT | 4 WELL AVG 1st Prod 10/2023 PHX NRI 0.286% LL 6,400’ IP24hr 21.1 MMCFPD NRM PROP 4,500 #/FT IP30 12.5 MMCFPD AETHON | ATTOYAC RIVER - SCOGGINS GAS UNIT | 3 WELL AVG 1st Prod 10/2023 PHX NRI 0.184% LL 8,600’ IP24hr 22.8 MMCFPD NRM PROP 4,500 #/FT IP30 15.3 MMCFPD AETHON | CLARK – ARMSTRONG UNIT | 5 WELL AVG 1st Prod 5/2024 PHX NRI 0.138% LL 10,900’ IP24hr 16.8 MMCFPD NRM PROP 4,400 #/FT IP30 11.6 MMCFPD AETHON | SILVER HAMMER / PATZAKIS | 4 WELL AVG 1st Prod 6/2023 PHX NRI 0.490% LL 8,200’ IP24hr 21.8 MMCFPD NRM PROP 4,800 #/FT IP30 15.6 MMCFPD South Texas Haynesville Update Notable Well Results5 Source: Company info and Enverus 1 As of 12/31/2024 2 Wells in Progress includes wells currently being drilled and wells waiting on completion 3 Active natural gas and oil horizontal permits filed 4 Rig data from Enverus as of 12/31/2024 5 NRIs are internal estimates and are subject to confirmation from operator Operators are drilling 3-5 wells per unit, and a positive indication of near term volumes and cashflows Since 2019, core development areas have been extended as new completion designs have lowered breakevens Key Operator is Aethon who has been the most active in the Shelby Trough PHX South Texas Haynesville Ownership1: 1,105 NRA (total PHX Haynesville ownership 8,979 NRA) Gross Wells In Progress on PHX1,2: 8 (total PHX Haynesville gross active WIPs 63) Gross Active Permits on PHX1,3: 0 (total PHX Haynesville gross active permits 23) Total Active Rigs in South Texas AOI4: 5 1 2 3 4 1 2 3 4
Springboard III Update Highest resource in-place per DSU in the midcontinent, co-developing the Mississippian Sycamore & Woodford Shale Operators starting to infill existing DSUs; Early results suggest very little to no Parent-Child degradation PHX Springboard III Ownership1,6: 4,129 NRA Gross Wells In Progress on PHX1,2: 23 Gross Active Permits on PHX1,3: 6 Gross Active Rigs in Springboard III4: 4 Notable Well Results5 Source: Company info and Enverus 1 As of 12/31/2024 2 Wells in Progress includes wells currently being drilled and wells waiting on completion 3 Active natural gas and oil horizontal permits filed 4 Rig data from Enverus as of 12/31/2024 5 NRIs are internal estimates and are subject to confirmation from operator 6 This does not reflect PHX’s most recent acquisition of 50 net royalty acres for ~$0.6 million on 1/2/2025 CONTINENTAL | COURBET 7-22-9XHW | WOODFORD 1st Prod 03/2023 PHX NRI 0.363% 10,700’ IP30 2,340 BOEPD NRM PROP 2,500 #/FT % OIL 52% CONTINENTAL | SUNDANCE KID 3-23-26-35XHM | SYCAMORE 1st Prod 03/2024 PHX NRI 0.418% LL 12,400’ IP30 2,150 BOEPD NRM PROP 2’500 #/FT % OIL 79% CONTINENTAL | COURBET 16-15-9XHM | SYCAMORE 1st Prod 03/2023 PHX NRI 0.771% LL 11,200’ IP30 3,230 BOEPD NRM PROP 2,500 #/FT % OIL 78% CONTINENTAL | HONDO 3-22-15XHM | SYCAMORE 1st Prod 02/2024 PHX NRI 2.584% LL 9,900’ IP30 3,400 BOEPD NRM PROP 2,500 #/FT % OIL 87% 1 2 3 4 1 2 3 4
STACK MERGE SCOOP MERAMEC OSAGE/SYCAMORE WOODFORD SHALE STACK | MERGE | SCOOP The SCOOP is the premier play in Oklahoma with the highest resource in-place and most horizontal objectives The transition between the SCOOP and STACK is the MERGE where the thickness prevents stacked development The primary target in the STACK is the Meramec All 3 regions are sourced by the Woodford and feature >1,350 btu gas and minimal produced water 1 PHX internally plans all undrilled inventory on a section-by-section basis, the above is a representation of the regional estimate of wells per section, however locally some areas will differ MERGE SCOOP STACK A A’ WOODFORD SHALE OSAGE MERAMEC WOODFORD SHALE SYCAMORE MERAMEC STACK MERGE SCOOP A A’ BOOKED LOCATION UNBOOKED LOCATION
Robust Acquisition Process 20 PHX believes that being the aggregator of choice in our core areas is a key component of our strategy Royalties, just like any other hydrocarbon asset class, are naturally depleting assets and reinvestment is required to maintain and grow cash flows over time We target minerals in our core areas (SCOOP and Haynesville) with full analysis of geology and established type curves in order to minimize execution risk Typical profile of acquisitions includes an already producing component as well as royalties that are either in the process of being developed (WIPs) or will be developed over time (locations) by reputable and creditworthy operators to minimize timing risk Focused on active operators in order to minimize development timing risk Our acquisition program targets returns well in excess of our cost of capital (see ROCE) to drive increasing shareholder value IRR Payback MOIC Commodity Pricing Geology Type Curves Title Review Takeaway Capacity Basin Differentials Development Timing Inputs Requirements PHX’s A&D Methodology
Acquisition Summary Acquisitions by Basin by Year (in thousands) Focused on highest quality rock in the SCOOP and Haynesville plays Targeting a mix of production, near term development opportunities via wells in progress and additional upside potential under high quality operators $35.6M in acquisitions in SCOOP and $94.0M in Haynesville since Q1 of 2020 Positioned For Growth Through Acquisitions Total domestic US mineral market estimated at ~$0.5 - 1 trillion(2) Highly fragmented Predominantly owned by private individuals PHX well positioned to be one of the premier consolidators in our core areas Focus on smaller deals increases opportunity set and potential returns Market Opportunity Midpoint (1) : 97% 1 As of 12/31/2024 2 Midpoint of market size estimate range. Based on production data from EIA and spot price as of 03/31/2021. Assumes 20% of royalties are on Federal lands and there is an average royalty burden of 18.75%. Assumes a 10x multiple on cash flows to derive total market size. Excludes NGL value and overriding royalty interests 3 Enterprise values of PHX, DMCP, KRP, BSM, STR and VNOM as of 03/31/2023 4 This does not reflect PHX’s most recent acquisition of 50 net royalty acres for ~$0.6 million on 1/2/2025 4
Acquisition History All acreage currently owned in the Haynesville and predominately all acreage currently owned in Springboard III area of interest was acquired under current management team’s guidance Source: Company information and Enverus; Map of active rigs as of 12/31/2024 1 As of 12/31/2024 1 1
Natural Gas – Continued Demand Growth Natural Gas Electrical Generation1 Monthly Electrical Generation by Fuel Type1 Natural Gas Consumption1 1 Source: EIA Natural gas demand from power generation continues to increase and dominate the power stack; increase in solar and wind are coming at the expense of coal 20 additional gas fired power plants with total capacity of 7.7 GW expected to come online in 2024 – 2025 LNG export capacity expected to increase as projects under construction come online in second half of 2024 and in 2025
Natural Gas – Surging LNG Demand Forecasted U.S. Export Annual Volume Growth1 Large Scale Approved Liquefaction Facilities 1 Current LNG export capacity is fully committed North America liquefied natural gas capacity is on track to more than double between 2024 and 2028 (US 9.7 Bcf/d, Canada 2.5 Bcf/d and Mexico 0.8 Bcf/d) US exported more LNG in 2023 than any other country; increasing exports 12% compared to 2022 Source: EIA. 1 Capacity based on baseload nameplate capacity 2 Expected online in 2H 2025 – 1H 2026 3 Expected online by end of 2024 4 Expected online in 2026 5 Expected online 2027 6 Expected online 2027 / 2028
Current Hedge Position Mix of collars and swaps designed to provide upside exposure while protecting downside risk Note: Volumes hedged through 12/31/2024 Gas hedge prices are in $/Mcf and Oil hedge prices are in $/bbl
Reconciliation of Non-GAAP Financial Measures Source: Company Filings
Reconciliation of Non-GAAP Financial Measures
Reconciliation of Non-GAAP Financial Measures Source: Company Filings
Reconciliation of Non-GAAP Financial Measures