UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K/A
(Amendment No. 5)
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (date of earliest event reported): July 12, 2018
Kimbell Royalty Partners, LP
(Exact name of registrant as specified in its charter)
Delaware |
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1-38005 |
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47-5505475 |
(State or other jurisdiction
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(Commission
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(I.R.S. Employer
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777 Taylor Street, Suite 810
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76102 |
(Address of principal executive offices) |
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(Zip Code) |
Registrants telephone number, including area code: (817) 945-9700
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 ( see General Instruction A.2):
¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
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 x
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. x
Introductory Note
As reported in a Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission by Kimbell Royalty Partners, LP, a Delaware limited partnership (the Partnership), on July 18, 2018 (the Original Form 8-K), on July 12, 2018, the Partnership completed its previously announced acquisition (the Acquisition) of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC (Haymaker Minerals) and Haymaker Properties, L.P. (Haymaker Properties).
On July 27, 2018, the Partnership filed an amendment (Amendment No. 1) to the Original Form 8-K to provide the historical financial statements of Haymaker Minerals and Haymaker Properties and the pro forma financial information of the Partnership giving effect to the Acquisition, as required by Item 9.01 of Form 8-K. On September 10, 2018, the Partnership filed an amendment (Amendment No. 2) to provide additional historical and pro forma information, through the quarter ended June 30, 2018, of Haymaker Minerals, Haymaker Properties and the Partnership (as applicable). On September 19, 2018, the Partnership filed an amendment (Amendment No. 3) to provide revised pro forma financial information, through the quarter ended June 30, 2018, of the Partnership, which reflected a correction to the pro forma reclassification of certain pro forma balance sheet items, including the reclassification of deposits on oil and natural gas properties and other assets. The pro forma information filed in Amendment No. 3 superseded the pro forma information previously filed in Amendment No. 2. On January 28, 2019, the Partnership filed an amendment (Amendment No. 4) to provide additional pro forma information, through the quarter ended September 30, 2018, of the Partnership pursuant to the applicable requirements of Rule 11-02 of Regulation S-X. The pro forma information that was previously filed by the Partnership in Amendment No. 1 and Amendment No. 3 was unchanged.
This amendment is filed to provide additional pro forma information, through the year ended December 31, 2018, of the Partnership pursuant to the applicable requirements of Rule 11-02 of Regulation S-X. The pro forma information that was previously filed by the Partnership in Amendment No. 1, Amendment No. 3 and Amendment No. 4 is unchanged.
Item 9.01. Financial Statements and Exhibits.
(b) Pro Forma Financial Information.
The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018, which gives effect to the Acquisition, is filed as Exhibit 99.1 hereto and incorporated by reference herein.
(d) Exhibits.
Number |
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Description |
99.1 |
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SIGNATURE
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.
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KIMBELL ROYALTY PARTNERS, LP |
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By: |
Kimbell Royalty GP, LLC, |
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its general partner |
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By: |
/s/ R. Davis Ravnaas |
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R. Davis Ravnaas |
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President and Chief Financial Officer |
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Date: March 12, 2019
Unaudited Pro Forma Condensed Combined Financial Statements
On July 12, 2018 (the Closing Date ), Kimbell Royalty Partners, LP, a Delaware limited partnership ( Kimbell or the Partnership ), completed its acquisition (the Acquisition ) of (i) all of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC, a Delaware limited liability company ( Haymaker Minerals ), pursuant to the Securities Purchase Agreement, dated as of May 28, 2018, by and among Kimbell, Haymaker Minerals and Haymaker Services, LLC, a Delaware limited liability company ( Haymaker Services ), and (ii) all of the equity interests in certain subsidiaries, including Haymaker Properties, L.P. ( Haymaker Properties ), owned by Haymaker Resources, LP, a Delaware limited partnership ( Haymaker Resources and, together with Haymaker Minerals, the Haymaker Sellers ), pursuant to the Securities Purchase Agreement, dated as of May 28, 2018, by and among Kimbell, Haymaker Resources and Haymaker Services (the Haymaker Resources Purchase Agreement ). The aggregate consideration for the Acquisition consisted of approximately $216.3 million in cash (including amounts held in escrow, after standard pre-closing adjustments) and the issuance of 10 million common units representing limited partner interests ( Common Units ), resulting in a total valuation of approximately $451.7 million based on a closing price of $23.54 per unit for Kimbells Common Units as of the Closing Date. The completion of the Acquisition is referred to herein as the Haymaker Closing. Prior to the Closing Date, EIGF Aggregator III LLC, a Delaware limited liability company, TE Drilling Aggregator LLC, a Delaware limited liability company, and Haymaker Management, LLC, a Texas limited liability company (each of the preceding entities, together with Haymaker Minerals, the Haymaker Holders ), were designated as the recipients of the portion of the Common Units issued as consideration in connection with the Haymaker Resources Purchase Agreement.
At the time of the Haymaker Closing, Kimbell also entered into an amendment (the Credit Agreement Amendment ) to Kimbells existing Credit Agreement, dated as of January 11, 2017 (the Original Credit Agreement and, the Original Credit Agreement as amended by the Credit Agreement Amendment, the Amended Credit Agreement ), by and among the Partnership, certain subsidiaries of the Partnership as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto. The Credit Agreement Amendment increased commitments under the Amended Credit Agreement, resulting in a fully underwritten $200 million revolving credit facility.
The Board of Directors of Kimbell Royalty GP, LLC, a Delaware limited liability company and the general partner of the Partnership, approved on July 2, 2018, a change in the Partnerships U.S. federal income tax status from a partnership to a corporation by means of a check-the-box election (the Tax Election ). On September 24, 2018, the Tax Election became effective. Following the Tax Election, the Partnership is treated as an entity taxable as a corporation for U.S. federal income tax purposes and the Partnership will pay entity-level U.S. federal income tax, currently at a flat rate of 21% on its taxable income, if any.
On the day immediately prior to the effectiveness of the Tax Election, (i) the Partnerships equity interest in Kimbell Royalty Operating, LLC, a Delaware limited liability company (the Operating Company ), was recapitalized into newly issued common units of the Operating Company ( OpCo Common Units ) and newly issued Series A Cumulative Convertible Preferred Units of the Operating Company ( OpCo Series A Preferred Units ), (ii) the Haymaker Holders and the Kimbell Art Foundation delivered and assigned to the Partnership the Common Units they owned, in exchange for (a) newly issued Class B common units representing limited partner interests in the Partnership (the Class B Units ) and (b) newly issued OpCo Common Units (iii) the Limited Liability Company Agreement of the Operating Company was amended and restated to reflect the foregoing transactions and (iv) the Second Amended and Restated Agreement of Limited Partnership of the Partnership was amended and restated to reflect the foregoing transactions (together with the Tax Election, the Up-C Transaction ). The Partnership pays U.S. federal income tax on income allocated from its ownership of OpCo Common Units and OpCo Series A Preferred Units. There was no step-up in tax basis on OpCo Common Units or OpCo Series A Preferred Units as a result of the Up-C Transaction, and no tax receivable agreement was entered into between the Partnership and the Haymaker Holders and the Kimbell Art Foundation. The Acquisition, the Credit Agreement Amendment and the Up-C Transaction are collectively referred to herein as the Pro Forma Transactions .
The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018 has been prepared to reflect the Pro Forma Transactions. The pro forma financial data is presented as if the Pro Forma Transactions had occurred on January 1, 2018.
The unaudited pro forma adjustments are based on preliminary estimates, accounting judgments and currently available information and assumptions that management believes are reasonable. The notes to the unaudited pro forma
condensed combined statement of operations provide a detailed discussion of how such adjustments were derived and presented in the unaudited pro forma financial information.
The unaudited pro forma condensed combined financial information has been prepared to reflect adjustments to the Partnerships historical financial information that are (i) directly attributable to the Pro Forma Transactions and (ii) factually supportable, and with respect to the unaudited pro forma condensed combined statement of operations, expected to have a continuing impact on the Partnerships results.
The unaudited pro forma condensed combined statement of operations is for informational purposes only and does not purport to represent what the Partnerships financial position and results of operations would have been had the Acquisition occurred on the dates indicated. This unaudited pro forma condensed combined financial information should not be used to project the Partnerships financial performance for any future period. A number of factors may affect the Partnerships results. Please read Risk Factors and Cautionary Statement Regarding Forward-Looking Statements in the Partnerships Annual Report on Form 10-K for the year ended December 31, 2018 (the Form 10-K ) for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in the Partnerships business.
The unaudited pro forma condensed combined financial information should be read in conjunction with the audited consolidated financial statements and notes thereto contained in the Form 10-K and each of the historical financial statements and notes thereto of each of Haymaker Minerals and Haymaker Properties, as filed in Amendment No. 1 to the Current Report on Form 8-K filed by the Partnership with the Securities and Exchange Commission on July 18, 2018.
Unaudited Pro Forma Condensed Combined Statement of Operations
For the Year Ended December 31, 2018
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Kimbell |
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Haymaker
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Haymaker
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Pro Forma |
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|||||
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Year Ended
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Period from January 1,
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Period from January 1,
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Pro Forma
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Year Ended
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Oil, natural gas and NGL revenues |
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$ |
65,713,112 |
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$ |
|
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$ |
|
|
$ |
23,667,490 |
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(C) |
$ |
88,226,707 |
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|
|
|
|
|
|
|
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(368,124 |
) |
(E) |
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|||||
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(785,771 |
) |
(D) |
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Crude oil and condensate sales |
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3,152,933 |
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6,048,098 |
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(9,201,031 |
) |
(C) |
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Natural gas sales |
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10,577,782 |
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1,351,999 |
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(11,929,781 |
) |
(C) |
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Natural gas liquids sales and other |
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1,581,258 |
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955,420 |
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(2,536,678 |
) |
(C) |
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Income from lease bonus |
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1,213,550 |
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259,445 |
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1,119,041 |
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368,124 |
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(E) |
2,960,160 |
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Gain on commodity derivative instruments |
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3,331,548 |
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3,331,548 |
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Total revenues |
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70,258,210 |
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15,571,418 |
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9,474,558 |
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(785,771 |
) |
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94,518,415 |
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Costs and expenses |
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Production and ad valorem taxes |
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4,399,667 |
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1,334,976 |
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(F) |
5,734,643 |
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Production ad valorem, and withholding taxes |
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778,482 |
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656,765 |
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(1,334,976 |
) |
(F) |
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|||||
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(100,271 |
) |
(D) |
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|||||
Production expense |
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1,815,625 |
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630,618 |
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(2,431,650 |
) |
(G) |
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(14,593 |
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(D) |
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Depreciation, depletion and accretion expense |
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25,213,043 |
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3,971,571 |
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2,534,303 |
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(6,505,874 |
) |
(A) |
33,960,015 |
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|||||
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8,746,972 |
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(A) |
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Impairment of oil and natural gas properties |
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67,311,501 |
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67,311,501 |
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Marketing and other deductions |
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4,652,313 |
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2,431,650 |
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(G) |
7,083,963 |
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General and administrative expense |
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16,847,328 |
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4,834,483 |
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3,281,048 |
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(5,458,064 |
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(I) |
19,504,795 |
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|||||
Total costs and expenses |
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118,423,852 |
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11,400,161 |
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7,102,734 |
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(3,331,830 |
) |
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133,594,917 |
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Operating (loss) income |
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(48,165,642 |
) |
4,171,257 |
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2,371,824 |
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2,546,059 |
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(39,076,502 |
) |
|||||
Other income (expense) |
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|
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(Loss) gain on derivatives |
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(736,696 |
) |
(632,594 |
) |
1,369,290 |
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(H) |
|
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|||||
Interest expense |
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(4,091,900 |
) |
(538,704 |
) |
(398,643 |
) |
5,029,247 |
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(B) |
(5,813,652 |
) |
|||||
|
|
|
|
|
|
|
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(5,813,652 |
) |
(B) |
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|||||
Other income |
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4,686 |
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17,710 |
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(22,396 |
) |
(J) |
|
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|||||
Total other income (expense) |
|
(4,091,900 |
) |
(1,270,714 |
) |
(1,013,527 |
) |
562,489 |
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(5,813,652 |
) |
|||||
(Loss) income before income taxes |
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(52,257,542 |
) |
2,900,543 |
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1,358,297 |
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3,108,548 |
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(44,890,154 |
) |
|||||
Income tax benefit |
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|
566 |
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|
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566 |
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|||||
Provision for income taxes |
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(24,681 |
) |
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(24,681 |
) |
|||||
Net (loss) income before Series A preferred unit distribution and accretion |
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(52,282,223 |
) |
2,900,543 |
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1,358,863 |
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3,108,548 |
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(44,914,269 |
) |
|||||
Distribution and accretion on Series A preferred units |
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(6,310,040 |
) |
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|
|
|
|
|
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(6,310,040 |
) |
|||||
Net (loss) income |
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(58,592,263 |
) |
2,900,543 |
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1,358,863 |
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3,108,548 |
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(51,224,309 |
) |
|||||
Net loss attributable to noncontrolling interests |
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(1,855,681 |
) |
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|
|
|
|
|
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(1,855,681 |
) |
|||||
Net (loss) income attributable to Kimbell Royalty Partners LP |
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(56,736,582 |
) |
2,900,543 |
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1,358,863 |
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3,108,548 |
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(49,368,628 |
) |
|||||
Distribution on Class B units |
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(30,967 |
) |
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|
|
|
|
|
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(30,967 |
) |
|||||
Net (loss) income attributable to common units |
|
$ |
(56,767,549 |
) |
$ |
2,900,543 |
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$ |
1,358,863 |
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$ |
3,108,548 |
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|
$ |
(49,399,595 |
) |
Net loss attributable to common units |
|
|
|
|
|
|
|
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|||||
Basic |
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$ |
(3.08 |
) |
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|
|
|
|
|
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$ |
(1.74 |
) |
|||
Diluted |
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$ |
(3.08 |
) |
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|
|
|
|
|
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$ |
(1.74 |
) |
|||
Weighted average number of common units outstanding |
|
|
|
|
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|
|
|
|
|
|
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|||||
Basic |
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18,442,234 |
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|
|
|
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10,000,000 |
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|
28,442,234 |
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|||||
Diluted |
|
18,442,234 |
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|
|
|
|
10,000,000 |
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|
28,442,234 |
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|||||
Distributions declared and paid per Common Unit |
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$ |
1.70 |
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|
|
|
|
|
|
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$ |
1.70 |
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For the Year Ended December 31, 2018
1) Basis of Presentation
The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018 is derived from the historical financial statements of Kimbell, Haymaker Minerals and Haymaker Properties.
2) Pro Forma Adjustments and Assumptions
The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual effects of the Pro Forma Transactions will differ from the pro forma adjustments. A general description of the pro forma adjustments is provided as follows:
A) To eliminate the historical depreciation, depletion and accretion expense related to the acquired oil and natural gas properties.
B) Reflects the Partnerships entrance into the Credit Agreement Amendment, and increased borrowings at the closing of the Acquisition of $105.0 million.
The Amended Credit Agreement bears interest at LIBOR plus a margin of 2.5%. The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018 used an estimated 4.62% interest rate on the outstanding borrowings under the Amended Credit Facility. The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018 estimated that the Partnership had total borrowings outstanding under the Amended Credit Agreement of $87.3 million. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense of approximately $0.9 million annually, assuming that the Partnerships indebtedness remained constant throughout the year.
The following table represents the impact of adjustments to interest expense:
|
|
|
|
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|
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Year Ended |
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|
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December 31, |
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|
|
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2018 |
|
|
New secured revolving credit facility: |
|
|
|
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Interest expense |
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$ |
5,322,365 |
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Amortization expense of loan origination costs |
|
491,287 |
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|
|
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5,813,652 |
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Pro forma adjustment of existing debt: |
|
|
|
|
Interest expense - Kimbell |
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(4,091,900 |
) |
|
Interest expense - Haymaker Properties |
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(538,704 |
) |
|
Interest expense - Haymaker Minerals |
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(398,643 |
) |
|
|
|
(5,029,247 |
) |
|
Net adjustment to interest expense |
|
$ |
784,405 |
|
C) Reflects the historical statement of operations related to the Acquisition, which also reflects a reclassification of approximately $23.7 million for the year ended December 31, 2018 related to crude oil and condensate sales, natural gas sales, and natural gas liquids (NGL) sales and other in order to conform the presentation to be consistent with the Partnerships presentation of such revenues within the oil, natural gas and NGL revenues line item in its historical statements of operations for the same periods.
D) Haymaker Minerals and Haymaker Properties sold assets to third parties prior to the Haymaker Closing. This pro forma adjustment reflects the reduction in revenues and direct expenses related to assets that were not acquired by the Partnership but that were included in the historical statements of operations of Haymaker Minerals and Haymaker Properties.
E) Reflects the reclassification of revenue related to lease bonus income that was previously recorded in the Partnerships oil, natural gas and NGL revenues.
F) Reflects the reclassification of production, ad valorem, and withholding taxes into production and ad valorem taxes.
G) Reflects the reclassification of production expense into marketing and other deductions.
H) Reflects the elimination of the impact of Haymaker Minerals and Haymaker Properties derivative instruments, which were terminated prior to the Haymaker Closing, from their respective historical statement of operations.
I) For the year ended December 31, 2018, Haymaker Minerals and Haymaker Properties incurred $2.2 million and $3.3 million, respectively, in transaction costs related to their divestiture to Kimbell. This proforma adjustment reflects the reduction in general and administrative expenses related to the historical statement of operations of Haymaker Minerals and Haymaker Properties.
J) Reflects the elimination of other income from Haymaker Minerals and Haymaker Properties historical statement of operations related to revenues that are not considered to be ongoing.
3) Pro Forma Net Income (Loss) per Common Unit
Pro forma net income (loss) per Common Unit is determined by dividing the pro forma net income (loss) available to common unitholders by the number of Common Units reflected in the unaudited condensed combined pro forma financial statements. All Common Units were assumed to have been outstanding since the beginning of the periods presented. The calculation of diluted net loss per Common Unit for the year ended December 31, 2018 excludes 1,157,924 non-vested, restricted Common Units issuable upon vesting and 5,945,946 additional Common Units, which represent the Series A Preferred Units on an as-converted basis, because their inclusion in the calculation would be anti-dilutive.
4) Pro Forma Supplemental Oil and Gas Reserve Information
The Partnership has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Partnerships audited consolidated statements of operations included in the Form 10-K for information about results of the Partnerships operations for oil and gas producing activities.
Capitalized oil and natural gas costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:
|
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December 31, |
|
|
|
|
2018 |
|
|
Oil, natural gas and NGL interests |
|
|
|
|
Proved properties |
|
$ |
538,290,590 |
|
Unevaluated properties |
|
280,304,353 |
|
|
Total oil, natural gas and NGL interests |
|
818,594,943 |
|
|
Accumulated depreciation, depletion, accretion and impairment |
|
(107,779,453 |
) |
|
Net oil, natural gas and NGL interests capitalized |
|
$ |
710,815,490 |
|
Costs incurred in oil and natural gas activities
Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows:
|
|
Year Ended
|
|
|
|
|
2018 |
|
|
Acquisition costs |
|
|
|
|
Proved properties |
|
$ |
243,227,632 |
|
Unevaluated properties |
|
288,334,110 |
|
|
Total |
|
531,561,742 |
|
|
Development costs |
|
|
|
|
Proved properties |
|
|
|
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Total |
|
|
|
|
Total costs incurred on oil, natural gas and NGL activities |
|
$ |
531,561,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities
The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnerships oil, natural gas and NGL operations.
|
|
Year Ended
|
|
|
|
|
2018 |
|
|
Oil, natural gas and NGL revenues |
|
$ |
65,713,112 |
|
Lease bonus and other income |
|
1,213,550 |
|
|
Production and ad valorem taxes |
|
(4,399,667 |
) |
|
Depreciation, depletion and accretion expense |
|
(25,213,043 |
) |
|
Impairment of oil and natural gas properties |
|
(67,311,501 |
) |
|
Marketing and other deductions |
|
(4,652,313 |
) |
|
Results of operations from oil, natural gas and NGLs |
|
$ |
(34,649,862 |
) |
The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves, and the estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2018 and 2017. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC.
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Proved reserves are those quantities of oil and 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. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
A Boe conversion ratio of six thousand cubic feet per barrel (6mcf/Bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
The Partnerships net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below:
|
|
Crude Oil and |
|
|
|
Natural Gas |
|
|
|
|
|
Condensate |
|
Natural Gas |
|
Liquids |
|
Total |
|
|
|
(MBbls) |
|
(MMcf) |
|
(MBbls) |
|
(MBOE) |
|
Net proved reserves at December 31, 2017 |
|
7,463 |
|
63,916 |
|
2,838 |
|
20,954 |
|
Revisions of previous estimates (1) |
|
194 |
|
1,754 |
|
952 |
|
1,437 |
|
Purchase of minerals in place (2) |
|
3,729 |
|
69,465 |
|
2,166 |
|
17,473 |
|
Production |
|
(591 |
) |
(7,874 |
) |
(310 |
) |
(2,213 |
) |
Net proved reserves at December 31, 2018 |
|
10,795 |
|
127,261 |
|
5,646 |
|
37,651 |
|
|
|
|
|
|
|
|
|
|
|
Net Proved Developed Reserves |
|
|
|
|
|
|
|
|
|
December 31, 2017 |
|
5,284 |
|
47,501 |
|
2,202 |
|
15,403 |
|
December 31, 2018 |
|
9,183 |
|
116,321 |
|
5,063 |
|
33,633 |
|
|
|
|
|
|
|
|
|
|
|
Net Proved Undeveloped Reserves |
|
|
|
|
|
|
|
|
|
December 31, 2017 |
|
2,179 |
|
16,415 |
|
636 |
|
5,551 |
|
December 31, 2018 |
|
1,612 |
|
10,940 |
|
583 |
|
4,018 |
|
(1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.
(2) Includes the acquisition of two packages of diverse mineral and royalty interests for a total of $243.2 million. The first acquisition totaling $155.7 million consists of mineral and royalty interests primarily in the Permian Basin, Haynesville Shale, Mid-Continent Area and Appalachia Region. The second acquisition totaling $87.5 million consists of mineral and royalty interests primarily in the Permian Basin, Eagle Ford Shale and Appalachia Region.
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
Standardized Measure
The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the properties is as follows (in thousands):
|
|
Year Ended
|
|
|
|
|
2018 |
|
|
Future cash inflows |
|
$ |
1,056,464 |
|
Future production costs |
|
(79,724 |
) |
|
Future state margin taxes |
|
(32,885 |
) |
|
Future income tax expense |
|
(41,241 |
) |
|
Future net cash flows |
|
902,614 |
|
|
Less 10% annual discount to reflect timing of cash flows |
|
(504,247 |
) |
|
Standard measure of discounted future net cash flows |
|
$ |
398,367 |
|
Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2018 were $65.56 per barrel for crude oil and $3.10 per Mcf for natural gas, respectively.
Future production costs are computed primarily by the Partnerships petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates.
Changes in Standardized Measure
Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands):
|
|
Year Ended
|
|
|
|
|
2018 |
|
|
Standardized measure - beginning of year |
|
$ |
215,552 |
|
Sales, net of production costs |
|
(56,661 |
) |
|
Net changes of prices and production costs related to future production |
|
11,355 |
|
|
Extensions, discoveries and improved recovery, net of future production costs |
|
|
|
|
Revisions of previous quantity estimates, net of related costs |
|
16,385 |
|
|
Net changes in state margin taxes |
|
(13,271 |
) |
|
Net changes in income taxes |
|
(17,232 |
) |
|
Accretion of discount |
|
21,555 |
|
|
Purchases of reserves in place |
|
175,885 |
|
|
Timing differences and other |
|
44,799 |
|
|
Standardized measure - end of year |
|
$ |
398,367 |
|