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Kimbell Royalty Partners, LP - Quarter Report: 2017 June (Form 10-Q)

Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10‑Q

 

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended: June 30, 2017

 

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                      to                    

Commission file number: 001‑38005


Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware
(State or other jurisdiction of
incorporation or organization)

1311
(Primary Standard Industrial
Classification Code Number)

47‑5505475
(I.R.S. Employer
Identification No.)

 

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

(817) 945‑9700

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒  No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒  No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

 

 

 

 

Large accelerated filer ☐

Accelerated filer ☐

Non‑accelerated filer ☒
(Do not check if a
smaller reporting company)

Smaller reporting company ☐

Emerging growth company ☒

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐  No ☒

As of August 8, 2017, 16,496,032 common units of the registrant were outstanding.


 

 

 

 


 

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

TABLE OF CONTENTS

 

 

PART I – FINANCIAL INFORMATION

Item 1.     Consolidated Financial Statements (Unaudited) 

2

Consolidated Balance Sheets 

2

Consolidated Statements of Operations  

3

Consolidated Statements of Changes in Partners’ Capital and Predecessor Members’ Equity  

4

Consolidated Statements of Cash Flows  

5

Notes to Consolidated Financial Statements 

6

Item 2.     Management’s Discussion and Analysis of Financial Condition and Results of Operations 

17

Item 3.     Quantitative and Qualitative Disclosures About Market Risk 

33

Item 4.     Controls and Procedures 

33

 

 

 

 

PART II – OTHER INFORMATION 

 

Item 1.     Legal Proceedings 

35

Item 1A.  Risk Factors 

35

Item 5.     Other Information 

35

Item 6.     Exhibits  

35

Signatures 

36

 

 

 

 

 

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PART I – FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements (Unaudited)

 

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(unaudited)

 

 

 

 

 

 

 

 

 

As of June 30, 

 

As of December 31, 

 

    

2017

    

2016

 

 

 

 

 

(Predecessor)

ASSETS

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

Cash and cash equivalents

 

$

5,827,370

 

$

505,880

Oil, natural gas and NGL receivables

 

 

4,962,172

 

 

474,103

Prepaid expenses

 

 

193,610

 

 

 —

Other receivables

 

 

 —

 

 

344,368

 

 

 

 

 

 

 

Total current assets

 

 

10,983,152

 

 

1,324,351

 

 

 

 

 

 

 

Property and equipment, net

 

 

209,825

 

 

261,568

 

 

 

 

 

 

 

Oil and natural gas properties

 

 

 

 

 

 

Oil and natural gas properties (full cost method)

 

 

285,040,146

 

 

70,888,121

Less: accumulated depreciation, depletion, accretion and impairment

 

 

(6,600,585)

 

 

(51,948,355)

Total oil and natural gas properties

 

 

278,439,561

 

 

18,939,766

 

 

 

 

 

 

 

Loan origination costs, net

 

 

286,458

 

 

13,046

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

289,918,996

 

$

20,538,731

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS' CAPITAL (PREDECESSOR MEMBERS' EQUITY)

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

Accounts payable

 

$

397,217

 

$

1,030,862

Other current liabilities

 

 

967,999

 

 

112,508

Asset retirement obligation, current portion

 

 

 —

 

 

27,013

 

 

 

 

 

 

 

Total current liabilities

 

 

1,365,216

 

 

1,170,383

 

 

 

 

 

 

 

Asset retirement obligation, net of current portion

 

 

 —

 

 

14,468

 

 

 

 

 

 

 

Other liabilities

 

 

 —

 

 

123,158

 

 

 

 

 

 

 

Long-term debt

 

 

18,265,090

 

 

10,598,860

 

 

 

 

 

 

 

TOTAL LIABILITIES

 

 

19,630,306

 

 

11,906,869

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

 

 

Predecessor members' equity

 

 

 —

 

 

8,631,862

Partners' capital

 

 

270,288,690

 

 

 —

 

 

 

 

 

 

 

TOTAL LIABILITIES AND PARTNERS' CAPITAL (PREDECESSOR MEMBERS' EQUITY)

 

$

289,918,996

 

$

20,538,731

The accompanying notes are an integral part of these consolidated financial statements.

 

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the period from February 8, 2017 to June 30, 

 

 

For the period from January 1, 2017 to February 7,

 

For the six months ended June 30, 

 

For the three months ended June 30, 

 

 

For the three months ended June 30, 

 

    

2017

  

  

2017

    

2016

 

2016

  

  

2017

 

 

 

 

 

 

(Predecessor)

 

 

 

 

Oil, natural gas and NGL revenues

 

$

12,305,342

 

 

$

318,310

 

$

1,603,393

 

$

847,740

 

 

$

7,751,998

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes

 

 

823,787

 

 

 

19,651

 

 

83,252

 

 

48,211

 

 

 

617,681

Depreciation, depletion and accretion expense

 

 

6,667,377

 

 

 

113,639

 

 

825,054

 

 

349,440

 

 

 

4,131,717

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,685,938

 

 

965,907

 

 

 

 —

Marketing and other deductions

 

 

643,807

 

 

 

110,534

 

 

249,823

 

 

152,255

 

 

 

386,681

General and administrative expense

 

 

3,392,375

 

 

 

532,035

 

 

788,500

 

 

422,711

 

 

 

2,181,293

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total costs and expenses

 

 

11,527,346

 

 

 

775,859

 

 

6,632,567

 

 

1,938,524

 

 

 

7,317,372

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income (loss)

 

 

777,996

 

 

 

(457,549)

 

 

(5,029,174)

 

 

(1,090,784)

 

 

 

434,626

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

243,127

 

 

 

39,307

 

 

210,485

 

 

105,197

 

 

 

182,975

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes

 

 

534,869

 

 

 

(496,856)

 

 

(5,239,659)

 

 

(1,195,981)

 

 

 

251,651

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

State income taxes

 

 

 —

 

 

 

 —

 

 

9,189

 

 

3,304

 

 

 

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

534,869

 

 

$

(496,856)

 

$

(5,248,848)

 

$

(1,199,285)

 

 

$

251,651

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.03

 

 

$

(0.82)

 

$

(8.69)

 

$

(1.99)

 

 

$

0.02

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

16,332,708

 

 

 

604,137

 

 

604,137

 

 

604,137

 

 

 

16,332,708

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

$

0.03

 

 

$

(0.82)

 

$

(8.69)

 

$

(1.99)

 

 

$

0.02

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

 

16,389,814

 

 

 

604,137

 

 

604,137

 

 

604,137

 

 

 

16,422,446

 

The accompanying notes are an integral part of these consolidated financial statements.

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL AND PREDECESSOR MEMBERS’ EQUITY

(unaudited)

 

 

 

 

 

 

 

    

Units

    

Total

Members' equity - December 31, 2016 (Predecessor)

 

604,137

 

$

8,631,862

 

 

 

 

 

 

Unit-based compensation

 

 —

 

 

50,422

 

 

 

 

 

 

Net loss

 

 —

 

 

(496,856)

 

 

 

 

 

 

Transfer of membership units to Rivercrest Royalties Holdings, LLC

 

(604,137)

 

 

(98,988)

 

 

 

 

 

 

 

 

 

 

 

 

Partners' capital - February 8, 2017

 

 —

 

 

8,086,440

 

 

 

 

 

 

Common units issued to Predecessor in exchange for oil and natural gas properties

 

1,191,974

 

 

 —

 

 

 

 

 

 

Common units issued to contributors in exchange for oil and natural gas properties

 

9,390,734

 

 

169,033,212

 

 

 

 

 

 

Common units sold to public

 

5,750,000

 

 

103,500,000

 

 

 

 

 

 

Underwriting discount and structuring fee incurred at initial public offering

 

 —

 

 

(7,245,000)

 

 

 

 

 

 

Distributions to unitholders

 

 —

 

 

(3,756,523)

 

 

 

 

 

 

Unit-based compensation

 

163,324

 

 

135,692

 

 

 

 

 

 

Net income

 

 —

 

 

534,869

 

 

 

 

 

 

Partners' capital - June 30, 2017

 

16,496,032

 

$

270,288,690

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

 

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

For the period from February 8, 2017 to June 30, 

 

 

For the period from January 1, 2017 to February 7,

 

For the six months ended June 30, 

 

    

2017

  

  

2017

    

2016

 

 

 

 

 

 

(Predecessor)

Cash flows from operating activities

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

534,869

 

 

$

(496,856)

 

$

(5,248,848)

Adjustments to reconcile net income (loss) to net cash from operating activities:

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion and accretion expense

 

 

6,667,377

 

 

 

113,639

 

 

825,054

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,685,938

Amortization of loan origination costs

 

 

26,042

 

 

 

4,241

 

 

21,522

Amortization of tenant improvement allowance

 

 

 —

 

 

 

(2,864)

 

 

(58,380)

Unit-based compensation

 

 

135,692

 

 

 

50,422

 

 

302,530

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL receivables

 

 

59,022

 

 

 

14,551

 

 

1,269,414

Prepaid expenses

 

 

(193,610)

 

 

 

 —

 

 

 —

Other receivables

 

 

 —

 

 

 

333,056

 

 

 —

Accounts payable

 

 

380,649

 

 

 

247,972

 

 

(1,345,476)

Other current liabilities

 

 

967,999

 

 

 

(77,442)

 

 

98,521

Net cash provided by operating activities

 

 

8,578,040

 

 

 

186,719

 

 

550,275

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

 

 

Purchases of property and equipment

 

 

(21,214)

 

 

 

 —

 

 

(15,287)

Purchase of oil and natural gas properties

 

 

(113,180,523)

 

 

 

(523)

 

 

(64,094)

Net cash used in investing activities

 

 

(113,201,737)

 

 

 

(523)

 

 

(79,381)

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

 

 

 

 

 

Proceeds from initial public offering

 

 

96,255,000

 

 

 

 —

 

 

 —

Distributions to unitholders

 

 

(3,756,523)

 

 

 

 —

 

 

 —

Borrowings on long-term debt

 

 

18,265,090

 

 

 

 —

 

 

 —

Repayments on long-term debt

 

 

 —

 

 

 

 —

 

 

(250,000)

Payment of loan origination costs

 

 

(312,500)

 

 

 

 —

 

 

(13,000)

Net cash provided by (used in) financing activities

 

 

110,451,067

 

 

 

 —

 

 

(263,000)

 

 

 

 

 

 

 

 

 

 

 

Increase in cash and cash equivalents

 

 

5,827,370

 

 

 

186,196

 

 

207,894

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents, beginning of period

 

 

 —

 

 

 

505,880

 

 

379,741

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

 

$

5,827,370

 

 

$

692,076

 

$

587,635

 

 

 

 

 

 

 

 

 

 

 

Supplemental cash flow information:

 

 

 

 

 

 

 

 

 

 

Cash paid for interest

 

$

109,539

 

 

$

34,505

 

$

60,110

Cash paid for taxes

 

$

 —

 

 

$

5,355

 

$

6,712

 

 

 

 

 

 

 

 

 

 

 

Non-cash investing and financing activities:

 

 

 

 

 

 

 

 

 

 

Capital expenditures and consideration payable included in accounts payable and other liabilities

 

$

16,568

 

 

$

 —

 

$

57

Capital expenditures through issuance of common units

 

$

176,404,698

 

 

$

 —

 

$

 —

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “the Partnership,” “our partnership,” “we,” “our,” “us” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “the Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership. References to “the Predecessor,” “our predecessor” or “Rivercrest” refer to Rivercrest Royalties, LLC, the predecessor for accounting and financial reporting purposes. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner.

On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units.  The mineral and royalty interests comprising the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the time of the IPO.  As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for time periods on or after the closing of the IPO refers to the Partnership as a whole.  The financial information for time periods prior to the closing of the IPO refers only to Rivercrest, the predecessor for accounting purposes and does not include the results of the Partnership as a whole. The mineral and royalty interests of the Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

 

NOTE 1—ORGANIZATION

 

Kimbell Royalty Partners, LP is a Delaware limited partnership formed on October 30, 2015. In connection with its formation, the Partnership issued a non-economic general partner interest in the Partnership to Kimbell Royalty GP, LLC, its general partner.  The Partnership has adopted a fiscal year-end of December 31.

On February 8, 2017, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units.  The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing of the IPO on February 8, 2017.  As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets.  Unless otherwise indicated, the financial information presented for time periods prior to the closing of the IPO is solely that of the Predecessor, Rivercrest Royalties, LLC and does not include the results of the Partnership as a whole.  For the time periods on or after the closing of the IPO, the financial information is that of the Partnership as a whole.  The interests underlying the oil, natural gas and natural gas liquids production revenues of the Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

The Predecessor is a Delaware limited liability company formed on October 25, 2013 to own oil, natural gas and natural gas liquids mineral and royalty interests in the United States of America (‘‘United States’’). In addition to mineral and royalty interests, the Predecessor’s assets include overriding royalty interests. These non-cost-bearing interests are collectively referred to as ‘‘mineral and royalty interests.’’ The Predecessor also had non-operated working interests in certain oil and natural gas properties. Prior to the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated asset retirement obligations (“ARO”) to an affiliated entity that was not contributed to the Partnership.

 

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information

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and with the instructions to Form 10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).  As a result, the accompanying unaudited interim consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP.  Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s and the Predecessor’s financial statements for the years ended December 31, 2016 and 2015, which are included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016.  In the opinion of the Partnership’s management, the unaudited interim consolidated financial statements contain all adjustments of a normal recurring nature necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP.  The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole.

Management Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities and the estimates of proved oil, natural gas and natural gas liquids reserves and related present value estimates of future net cash flows from those properties.

The discounted present value of the proved oil, natural gas and natural gas liquids reserves is a major component of the ceiling test calculation and requires subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and natural gas liquids reserves based on the same information.

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in a ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

Reclassification of Prior Period Presentation

Certain prior period amounts have been reclassified for consistency with the current period presentation. 

 

Cash and Cash Equivalents

The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.

Accounts Receivable

Oil, natural gas and NGL receivables consist of revenue amounts due to the Partnership from its mineral and royalty interests. The Predecessor’s other receivables are amounts due as reimbursement for costs incurred by the Predecessor.  Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership was entitled to receive royalty payments with respect to the acquired

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properties from and after February 1, 2017.  Included in our oil, natural gas and NGL receivables are payments due to us by the Contributing Parties for oil, natural gas and NGL production contained in operator checks dated after February 1, 2017 and containing production related to months prior to February 1, 2017.  As of June 30, 2017, these amounts due to the Partnership from the Contributing Parties were $0.2 million.  The Partnership estimates and records an allowance for doubtful accounts when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of June 30, 2017 and December 31, 2016, no allowance for doubtful accounts is deemed necessary based upon a review of current receivables and the lack of historical write offs.

Property and Equipment

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease. Depreciation expense for the period from January 1, 2017 to February 7, 2017 and for the period from February 8, 2017 to June 30, 2017 was $6,166 and $66,792, respectively, for a combined depreciation expense of $72,958 for the six months ended June 30, 2017.  As of June 30, 2017 and December 31, 2016, property and equipment consisted of the following:

 

 

 

 

 

 

 

 

    

As of June 30, 2017

 

As of December 31, 2016

 

 

 

 

(Predecessor)

Computer hardware and equipment

    

$

16,421

    

$

8,927

Office furniture and equipment

 

 

33,811

 

 

42,337

Leasehold improvements

 

 

226,385

 

 

323,407

Less: accumulated depreciation

 

 

(66,792)

 

 

(113,103)

Property and equipment, net

 

$

209,825

 

$

261,568

 

Oil and Natural Gas Properties

The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.

The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and natural gas liquids reserves discounted at 10% plus the lower of cost or market value of unproved properties. The Partnership has not assigned any value to unproved properties in which it holds an interest. The full-cost ceiling is evaluated at the end of each period and additionally when events indicate possible impairment.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and natural gas liquids reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12‑month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves.  Oil, natural gas and natural gas liquids prices have historically been volatile and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices.

No impairment expense was recorded for the period from February 8, 2017 to June 30, 2017.  The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO.  The fair value of these acquired assets was based on the common units issued to the Contributing Parties, other than the Predecessor, multiplied by the IPO price per common unit plus the net proceeds of the IPO that were distributed to the Contributing Parties, excluding the value of any common units or net proceeds distributed to the Predecessor.  In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined  the fair value of the acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation.  This exemption was effective beginning with the period ended March 31, 2017 and will remain effective

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through all financial reporting periods through December 31, 2017.  A component of the exemption received from the SEC is that we are required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate.  As of June 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, the Partnership considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors.  Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO, and management affirmed that there has not been a material change to the fair value of these acquired assets since the IPO.  The properties acquired at the closing of our IPO have an unamortized cost at June 30, 2017 of $244.4 million.  Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $82.3 million for the period ending June 30, 2017.  The Partnership will continue to assess the fair value of the acquired assets at each periodic reporting date to ensure inclusion in the ceiling calculation is not required through the December 31, 2017 reporting period, which is the period of the exemption extended by the SEC.  Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired.  The assets contributed by our Predecessor and the assets acquired during the three months ended June 30, 2017, as described in Note 3―Acquisitions, were subject to the full-cost ceiling test.  No impairment expense was recorded for the period from February 8, 2017 to June 30, 2017 for the assets contributed by our Predecessor or the assets acquired during the three months ended June 30, 2017.

No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017.  The Predecessor recorded a full-cost ceiling impairment charge of $4.7 million for the six months ended June 30, 2016, as a result of reductions in estimated proved reserves and reduced commodity prices.     

The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and natural gas liquids reserves. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change.

Proceeds from other dispositions of oil and natural gas properties are credited to the full-cost pool. No gains or losses were recorded for the periods from January 1, 2017 to February 7, 2017, the period from February 8, 2017 to June 30, 2017 or the six months ended June 30, 2016.

Due to the nature of the Predecessor’s and the Partnership’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the periods from January 1, 2017 to February 7, 2017, the period from February 8, 2017 to June 30, 2017 or the six months ended June 30, 2016.

Asset Retirement Obligations

Prior to the transactions that were completed in connection with the closing of the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership.  The Predecessor’s ARO reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Predecessor’s non-operated working interests in oil and natural gas properties.

Fair values of legal obligations to retire and remove long-lived assets were recorded when the obligation was incurred. When the liability was initially recorded, the Predecessor capitalized this cost by increasing the carrying amount of the related property and equipment. Over time, the liability was accreted for the change in its present value and the capitalized cost in oil and natural gas properties was depleted based on units of production consistent with the related asset.

Other Long-Term Liabilities

The Predecessor’s other long-term liabilities consist of a tenant improvement allowance granted at the effective date of the lease for the Partnership’s office space. This allowance was accounted for as a deferred incentive and was being amortized over the term of the lease as a reduction to rent expense.  The deferred incentive was fully realized through the

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transactions that were completed in connection with the closing of the Partnership’s IPO and is not recognized in the Partnership’s financial statements.

Income Taxes

The Partnership is a master limited partnership and is taxed as a partnership under the Internal Revenue Code whereby the Partnership’s partners are taxed on their proportionate share of taxable income. The financial statements, therefore, do not include a provision for federal income taxes.

Texas imposes a franchise tax (commonly referred to as the Texas margin tax, which is considered an income tax) at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. During the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017, the Predecessor and the Partnership did not pay any state income taxes.  The Predecessor and the Partnership incurred de minimis amounts of state income taxes during the period from January 1, 2017 to February 7, 2017 and the period from February 8 to June 30, 2017, respectively.  For the six months ended June 30, 2016, the Predecessor incurred income taxes in Texas and other states amounting to $9,189.

Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership and the Predecessor had no uncertain tax positions at June 30, 2017 and December 31, 2016, respectively.

The Predecessor and the Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the period from January 1, 2017 to February 7, 2017, the period from February 8, 2017 to June 30, 2017 and the six months ended June 30, 2016, the Predecessor and the Partnership did not recognize any interest or penalty expense related to uncertain tax positions.

The Partnership has filed all tax returns to date that are currently due. Tax years after December 31, 2013 remain subject to possible examination by taxing authorities although no such examination has been requested.

Concentration of Credit Risk

The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and natural gas liquids produced and sold from its properties. It is believed that the loss of any single customer would not have a material adverse effect on the results of operations.

At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits.

Revenue Recognition

The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and natural gas liquids sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and natural gas liquids produced and sold from the properties.

To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within oil, natural gas and NGL receivables in the accompanying unaudited

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consolidated balance sheets. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.

Fair Value Measurements

The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable, as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future.

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:

·

Level 1—quoted market prices for identical assets or liabilities in active markets.

·

Level 2—quoted market prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.

·

Level 3—unobservable inputs for the asset or liability.

The Predecessor’s ARO is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 8 for the summary of changes in the fair value of the Predecessor’s ARO for the period from January 1, 2017 to February 7, 2017.

Recently Issued Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, “Business Combinations - Clarifying the Definition of a Business.” This update apples to all entities that must determine whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.  The update requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the transaction should not be accounted for as a business. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years. This update should be applied prospectively on or after the effective date. This update is not expected to have a material impact on the Partnership’s financial statements or results of operations. The adoption of this update will change the process that the Partnership uses to evaluate whether it has acquired a business or an asset. This update will be applied prospectively and will not have an effect on prior acquisitions.

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows - Restricted Cash.” This update affects entities that have restricted cash or restricted cash equivalents. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. This update will be applied retrospectively. The Partnership does not expect the adoption of this standard to have a material impact on the Partnership’s financial statements.

 

In June 2016, the FASB issued ASU 2016‑13, "Measurement of Credit Losses on Financial Instruments." ASU 2016‑13 changes the impairment model for most financial assets and certain other instruments, including trade and other

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receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Partnership does not believe this standard will have a material impact on its financial statements.

In April 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing.” This update clarifies two principles of Accounting Standards Codification (“ASC”) Topic 606, identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity.

 

In March 2016, the FASB issued ASU 2016‑09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016‑09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year.  The Partnership adopted this standard effective at the issuance of its restricted units under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) on May 12, 2017. The Partnership elected to account for forfeitures as they occur as a result of adopting this standard. 

In March 2016, the FASB issued ASU 2016-08, “Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net).”  Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, and early application is not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Partnership is still evaluating the impact of this standard, however, it does not expect that there will be a significant change in the manner of the Partnership’s revenue recognition. The Partnership expects that certain additional disclosures will be required upon adoption of this standard. The Partnership is still determining which adoption method it will use.

 

In February 2016, the FASB issued ASU 2016‑02, "Leases." ASU 2016‑02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases.  The Partnership is evaluating the new guidance and has not determined the impact this standard may have on its financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue From Contracts with Customers (Topic 606).” an ASU on a comprehensive new revenue recognition standard that will supersede ASC 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either ‘‘full retrospective’’ adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or ‘‘modified retrospective’’ adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.

Based upon the analysis done this far, the Partnership has not identified any revenue streams that would be materially impacted and does not expect the adoption of this standard to have a material effect on the Partnership’s financial statements. Our approach includes performing a detailed review of each of our revenue streams and comparing our

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historical accounting policies to the new standard.  The Partnership is still evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures and anticipates using the modified retrospective method to adopt the new standard.

 

 

NOTE 3—ACQUISITIONS

During the period from February 8, 2017 through June 30, 2017, the Partnership acquired mineral and royalty interests underlying 1,116,874 gross acres (6,881 net royalty acres) for an aggregate purchase price of approximately $16.8 million.  The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.

 

NOTE 4—LONG-TERM DEBT

In connection with its IPO, the Partnership entered into a $50.0 million secured revolving credit facility that is secured by substantially all of its assets and the assets of its wholly owned subsidiaries. Availability under the secured revolving credit facility equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will be re-determined semi-annually on February 1 and August 1 of each year based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the its wholly owned subsidiaries.  In connection with the August 1 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million.  Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0 million.  The secured revolving credit facility permits aggregate commitments to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.  The secured revolving credit facility matures on February 8, 2022. 

The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facility also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control.  As of June 30, 2017, the Partnership’s outstanding balance was $18.3 million.

During the period ended June 30, 2017, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% and Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%.  For the period from February 8, 2017 to June 30, 2017, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.38%.  The Partnership was in compliance with all of the covenants included in the secured revolving credit facility as of June 30, 2017.

On January 31, 2014, the Predecessor entered into a credit agreement with Frost Bank for up to a $50.0 million revolving credit facility.  The credit facility was subject to borrowing base restrictions and was collateralized by certain properties.  The borrowing based on the Predecessor’s credit facility was $20.0 million with interest payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans, with all principal and unpaid interest due at maturity on January 15, 2018.  As of December 31, 2016, the Predecessor had outstanding advances on long-term debt totaling $10.6 million.  On February 8, 2017, the Predecessor repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the sale of the Predecessor’s mineral and royalty interests to the Partnership.

 

NOTE 5—COMMON UNITS

On February 8, 2017, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the initial assets were contributed to the Partnership by the

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Contributing Parties at the time of the IPO.  On May 12, 2017, the Partnership issued 163,324 restricted units under the LTIP.  As of June 30, 2017, 16,496,032 common units of the Partnership were outstanding.

NOTE 6—EARNINGS PER UNIT

The Partnership’s earnings per unit (‘‘EPU’’) on the consolidated statements of operations is based on the net income of the Partnership for the period from February 8, 2017 to June 30, 2017.  The Predecessor’s EPU on the consolidated statements of operations is based on the net loss of the Predecessor for the period from January 1, 2017 to February 7, 2017 and for the six months ended June 30, 2016, since this is the amount of net loss that is attributable to the Predecessor’s membership interests. 

Basic EPU is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested common units granted under the Partnership’s 2017 LTIP for its employees, directors and consultants and unvested options granted under the Predecessor’s long-term incentive plan as described in Note 7—Unit-Based Compensation. For the period from January 1, 2017 to February 7, 2017 and for the six months ended June 30, 2016, the effect of the 110,000 options issued under the Predecessor’s long-term incentive plan would be anti-dilutive. Therefore, the options issued under the Predecessor’s long-term incentive plan were not included in the diluted EPU calculation on the consolidated statements of operations.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

For the period from February 8, 2017 to June 30, 

 

 

For the period from January 1, 2017 to February 7,

    

For the six months ended June 30, 

 

For the three months ended June 30, 

 

 

For the three months ended June 30, 

 

 

2017

  

  

2017

    

2016

 

2016

  

 

2017

 

 

 

 

 

 

(Predecessor)

 

 

 

 

Net income (loss) attributable to the period

 

$

534,869

 

 

$

(496,856)

 

$

(5,248,848)

 

$

(1,199,285)

 

 

$

251,651

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common units:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.03

 

 

$

(0.82)

 

$

(8.69)

 

$

(1.99)

 

 

$

0.02

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

16,332,708

 

 

 

604,137

 

 

604,137

 

 

604,137

 

 

 

16,332,708

Net income (loss) attributable to common units:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

$

0.03

 

 

$

(0.82)

 

$

(8.69)

 

$

(1.99)

 

 

$

0.02

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

 

16,389,814

 

 

 

604,137

 

 

604,137

 

 

604,137

 

 

 

16,422,446

 

 

NOTE 7—UNIT-BASED COMPENSATION

The Partnership’s LTIP authorizes grants of up to 2,041,600 common units in the aggregate to its employees, directors and consultants.  The restricted units issued under our LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date.  Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award.  Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants will be accrued for services provided during the intervening periods between the grant and vesting dates, utilizing then-current fair values for the awards and applying mark-to-market accounting until actual vesting occurs.

 

Distributions related to the restricted units are paid concurrently with our distributions for common units. The fair value of our restricted units issued under our LTIP to our employees and directors is determined by utilizing the market

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value of our common units on the respective grant date and the restricted units issued to non-employee consultants will be expensed utilizing current fair values for the awards and apply mark-to-market accounting until vesting occurs.

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

    

Weighted

    

Weighted

    

Weighted

 

 

 

 

Average

 

Average

 

Average

 

 

 

 

Grant-Date

 

Market-Date

 

Remaining

 

 

 

 

Fair Value

 

Fair Value

 

Contractual

 

 

Units

 

per Unit

 

per Unit

 

Term

Unvested at February 8, 2017

 

 

$

 

$

 

Granted - service condition employees

 

143,318

 

 

18.655

 

 

 

Granted - service condition consultants

 

20,006

 

 

 

 

16.830

 

Vested

 

 

 

 

 

 

Forfeited

 

 

 

 

 

 

Exercised

 

 

 

 

 

 

Unvested at June 30, 2017

 

163,324

 

$

18.655

 

$

16.830

 

1.867 years

 

Prior to the IPO, the Predecessor had a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options as compensation for services performed for the Predecessor. The options carried a distribution right, whereby the option holder received distributions that were commensurate with those given to holders of membership units.

A summary of the option activity as of February 7, 2017, is as follows:

 

 

 

 

 

 

 

 

 

    

 

    

 

 

    

Weighted

 

 

 

 

Weighted

 

Average

 

 

 

 

Average

 

Remaining

 

 

 

 

Exercise

 

Contractual

 

 

Units

 

Price

 

Term

Outstanding, December 31, 2016 (Predecessor)

 

110,000

 

$

100

 

8.00 years

Granted

 

 

 

 

Forfeited

 

 

 

 

Exercised

 

 

 

 

Outstanding, February 7, 2017

 

110,000

 

$

100

 

7.92 years

Exercisable, February 7, 2017

 

 

$

 

 

For the period from January 1, 2017 to February 7, 2017 and for the six months ended June 30, 2016, total compensation expense for awards under the Predecessor’s long-term incentive plan was $50,422 and $302,530 respectively, and is included general and administrative expenses in the unaudited consolidated statements of operations.  In connection with the transactions that were completed at the closing of the Partnership’s IPO, the outstanding options to purchase membership units under the Predecessor’s long-term incentive plan expired and were not converted to units in the Partnership.

 

 

NOTE 8—ASSET RETIREMENT OBLIGATIONS

 

Prior to the transactions that were completed in connection with the IPO, the Predecessor assigned its non-operated working interests and associated $41,578 ARO to an affiliated entity that was not contributed to the Partnership. As of the closing of its IPO and through the date of this Quarterly Report on Form 10-Q, the Partnership did not own any working interests and did not have any ARO or any lease operating expenses as a working interest owner.

 

 

NOTE 9—RELATED PARTY TRANSACTIONS

In connection with the IPO, the Partnership entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with Steward Royalties, LLC (‘‘Steward Royalties’’), Taylor Companies Mineral Management, LLC (‘‘Taylor Companies’’), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (‘‘Nail Bay Royalties’’) and Duncan Management, LLC (‘‘Duncan Management’’) pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under

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each of their respective service agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective service agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders.  During the period from February 8, 2017 to June 30, 2017, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $166,667, $166,667, $50,000, $209,807 and $274,359, respectively.  Certain consultants who provide services under the above mentioned management services agreements were granted restricted units under the Partnership’s LTIP on May 12, 2017.

During the period from January 1, 2017 to February 7, 2017, and for the six months ended June 30, 2016, the Predecessor’s activities included certain related party receivables and payables; however, such amounts were de minimis at February 7, 2017 and December 31, 2016.

 

NOTE 10—ADMINISTRATIVE SERVICES

The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business efforts. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the General Partner’s Board of Directors (the “Board of Directors”) and their affiliated entities.  See Note 9 ― Related Party Transactions.

 

NOTE 11—COMMITMENTS AND CONTINGENCIES

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity.

 

NOTE 12—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to June 30, 2017 in the preparation of its consolidated financial statements.

On July 28, 2017, the Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The distribution will be paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017.

 

On August 9, 2017, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant, contingent upon the filing of this Quarterly Report of (i) common units in an amount equal to $30,000 to each non-employee director of the Partnership under the LTIP, which shall be fully vested as of the grant date, and (ii) a total of 4,247 restricted units to certain consultants under the LTIP.

.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of financial condition and results of operations should be read together  in conjunction with our unaudited financial statements and notes thereto presented in this Quarterly Report on Form  10-Q (this “Quarterly Report”), as well as the historical financial statements of our accounting predecessor for accounting and financial reporting purposes, Rivercrest Royalties, LLC, (“Rivercrest” or the “Predecessor”) included in our Annual Report on Form 10-K for the year ended December 31, 2016.

On February 8, 2017, Kimbell Royalty Partners, LP (the “Partnership,” “we” or “us”) completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests comprising our initial assets were contributed to us by certain entities and individuals (the “Contributing Parties”), including certain affiliates of our founders (our “Sponsors”) at the time of our IPO.  As a result, as of December 31, 2016, we had not yet acquired any of such assets.

Unless otherwise indicated in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical financial information presented for time periods on or after the closing of the IPO refers to the Partnership as a whole.  The financial information for time periods prior to the closing of the IPO refers only to Rivercrest, the predecessor for accounting purposes and does not include the results of the Partnership as a whole. The interests underlying the oil, natural gas and natural gas liquids production revenues of our Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

 

Cautionary Statement Regarding Forward‑Looking Statements

Certain statements and information in this Quarterly Report may constitute forward‑looking statements. Forward‑looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward‑looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward‑looking statements can be guaranteed. When considering these forward‑looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward‑looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward‑looking statements include:

·

our ability to execute our business strategies;

·

the volatility of realized prices for oil, natural gas and natural gas liquids;

·

the level of production on our properties;

·

the level of drilling and completion activity by the operators of our properties;

·

regional supply and demand factors, delays or interruptions of production;

·

our ability to replace our reserves;

·

our ability to identify and complete acquisitions of assets or businesses;

·

general economic, business or industry conditions;

·

competition in the oil and natural gas industry;

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·

the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;

·

title defects in the properties in which we invest;

·

uncertainties with respect to identified drilling locations and estimates of reserves;

·

the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;

·

restrictions on or the availability of the use of water in the business of the operators of our properties;

·

the availability of transportation facilities;

·

the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

·

federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing and other matters affecting the oil and gas industry;

·

future operating results;

·

exploration and development drilling prospects, inventories, projects and programs;

·

operating hazards faced by the operators of our properties;

·

the ability of the operators of our properties to keep pace with technological advancements; and

·

certain factors discussed elsewhere in this report.

All forward‑looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

Overview

Kimbell Royalty Partners, LP is a Delaware limited partnership formed to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids from the acreage underlying our interests, net of post‑production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of June 30, 2017, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 2.0 million gross acres, with approximately 35% of our aggregate acres located in the Permian Basin. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of June 30, 2017, over 95% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 50,000 gross producing wells, including over 29,000 wells in the Permian Basin.

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Recent Developments

During the period from February 8, 2017 through June 30, 2017, the Partnership acquired mineral and royalty interests underlying 1,116,874 gross acres (6,881 net royalty acres) for an aggregate purchase price of approximately $16.8 million.  The Partnership funded these acquisitions with borrowings under its revolving credit facility.

Business Environment

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. In late 2014, prices for oil and natural gas declined precipitously, and prices remained low throughout 2015 and for the majority of 2016 until rebounding in the fourth quarter of 2016.  During the six months ended June 30, 2017, WTI ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $54.48 per Bbl on February 23, 2017, and during the six months ended June 30, 2016, WTI ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $51.23 per Bbl on June 8, 2016.  During the six months ended June 30, 2017, the Henry Hub spot market price of natural gas has ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017.  During the six months ended June 30, 2016, Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $2.94 per MMBtu on June 30, 2016.  On July 31, 2017, the WTI posted price for crude oil was $50.21 per Bbl and the Henry Hub spot market price of natural gas was $2.87 per MMBtu.

The following table, as reported by the U.S. Energy Information Administration (“EIA”), sets forth the average prices for oil and natural gas for the three months and six months ended as of June 30, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended June 30, 

 

For the six months ended June 30, 

EIA Average Price:

 

2017

    

2016

 

2017

    

2016

Oil (Bbl)

 

$

48.10

 

$

45.46

 

$

49.85

 

$

45.46

Natural gas (MMBtu)

 

$

3.08

 

$

2.15

 

$

3.05

 

$

2.07

Source: EIA

Rig Count

The Baker Hughes U.S. Rotary Rig count was 940 active rigs at June 30, 2017, a greater than 118% increase from 431 active rigs at July 1, 2016.  In addition, according to the Baker Hughes U.S. Rotary Rig count, rig activity in the 20 states in which we own mineral and royalty interests increased more than 123% from 385 active rigs at July 1, 2016 to 862 active rigs at June 30, 2017.  The active rig count across our acreage during the three months ended June 30, 2017 held steady at 24 rigs, which is significantly higher than the 15 rig count at year-end 2016.

Sources of Our Revenue

Our revenues and our Predecessor’s revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and natural gas liquids production, as well as the sale of natural gas liquids that are extracted from natural gas during processing.  For the three months ended June 30, 2017, our revenues were generated 58% from oil sales, 31% from natural gas sales and 11% from natural gas liquids sales. For the three months ended June 30, 2016, our Predecessor’s revenues were generated 67% from oil sales, 25% from natural gas sales and 8% from natural gas liquids sales.  For the period from January 1, 2017 to February 7, 2017, our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from natural gas liquids sales. For the period from February 8, 2017 to June 30, 2017, our revenues were generated 60% from oil sales, 29% from natural gas sales and 11% from natural gas liquids sales. For the combined six months ended June 30, 2017, the revenues were generated 60% from oil sales, 29% from natural gas sales and 11% from natural gas liquids sales.  For the six months ended June 30, 2016, our Predecessor’s revenues were generated 63% from oil sales, 28% from natural gas sales and 10% from natural gas liquids sales.  Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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Neither we nor our Predecessor entered into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas and natural gas liquids produced from our mineral and royalty interests. As a result, we may realize the benefit of any short‑term increase in the price of oil, natural gas and natural gas liquids, but we will not be protected against decreases in price, and if the price of oil, natural gas and natural gas liquids decreases significantly, our business, results of operation and cash available for distribution may be materially adversely effected. We may enter into hedging arrangements in the future.

Adjusted EBITDA

Adjusted EBITDA is used as a supplemental non-GAAP (as defined below) financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.

We define Adjusted EBITDA as net income (loss) plus interest expense, net of capitalized interest, non‑cash unit‑based compensation, impairment of oil and natural gas properties, income taxes and depreciation, depletion and accretion expense. Adjusted EBITDA is not a measure of the income (loss) as determined by the generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

Adjusted EBITDA should not be considered an alternative to net income, oil, natural gas and natural gas liquids revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following tables present a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for the periods indicated (unaudited):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the period from February 8, 2017 to June 30, 

 

 

For the period from January 1, 2017 to February 7,

 

For the six months ended June 30, 

 

For the three months ended June 30, 

 

 

For the three months ended June 30, 

 

 

2017

    

    

2017

 

2016

 

2016

    

    

2017

 

 

 

 

 

 

(Predecessor)

 

 

 

 

Net income (loss)

 

$

534,869

    

    

$

(496,856)

 

$

(5,248,848)

    

$

(1,199,285)

    

    

$

251,651

Depreciation, depletion and accretion expense

 

 

6,667,377

 

 

 

113,639

 

 

825,054

 

 

349,440

 

 

 

4,131,717

Interest expense

 

 

243,127

 

 

 

39,307

 

 

210,485

 

 

105,197

 

 

 

182,975

Income taxes

 

 

 —

 

 

 

 —

 

 

9,189

 

 

3,304

 

 

 

 —

EBITDA

 

 

7,445,373

 

 

 

(343,910)

 

 

(4,204,120)

 

 

(741,344)

 

 

 

4,566,343

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,685,938

 

 

965,907

 

 

 

 —

Unit‑based compensation

 

 

135,692

 

 

 

50,422

 

 

302,530

 

 

151,265

 

 

 

135,692

Adjusted EBITDA

 

$

7,581,065

 

 

$

(293,488)

 

$

784,348

 

$

375,828

 

 

$

4,702,035

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash interest expense

 

 

109,539

 

 

 

34,505

 

 

60,110

 

 

123,091

 

 

 

105,625

Capital expenditures

 

 

 —

 

 

 

 —

 

 

 —

 

 

12,274

 

 

 

 —

Cash available for distribution

 

$

7,471,526

 

 

$

(327,993)

 

$

724,238

 

$

240,463

 

 

$

4,596,410

 

 

 

 

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For the period from February 8, 2017 to June 30, 

 

 

For the period from January 1, 2017 to
February 7,

 

For the six months ended June 30, 

 

For the three months ended June 30, 

 

 

For the three months ended June 30, 

 

 

2017

    

    

2017

 

2016

 

2016

    

    

2017

 

 

 

 

 

 

(Predecessor)

 

 

 

 

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

8,578,040

 

 

$

186,719

 

$

550,275

 

$

355,160

 

 

$

5,826,652

Interest expense

 

 

243,127

 

 

 

39,307

 

 

210,485

 

 

105,197

 

 

 

182,975

State income taxes

 

 

 —

 

 

 

 —

 

 

9,189

 

 

3,304

 

 

 

 —

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

(4,685,938)

 

 

(965,907)

 

 

 

 —

Amortization of loan origination costs

 

 

(26,042)

 

 

 

(4,241)

 

 

(21,522)

 

 

(11,281)

 

 

 

(15,625)

Amortization of tenant improvement allowance

 

 

 —

 

 

 

2,864

 

 

58,380

 

 

38,837

 

 

 

 —

Unit-based compensation

 

 

(135,692)

 

 

 

(50,422)

 

 

(302,530)

 

 

(151,265)

 

 

 

(135,692)

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL revenues receivable

 

 

(59,022)

 

 

 

(14,551)

 

 

(1,269,414)

 

 

96,058

 

 

 

(1,744,974)

Prepaid expenses

 

 

193,610

 

 

 

 —

 

 

 —

 

 

 —

 

 

 

(82,415)

Other receivables

 

 

 —

 

 

 

(333,056)

 

 

 —

 

 

 —

 

 

 

 —

Accounts payable

 

 

(380,649)

 

 

 

(247,972)

 

 

1,345,476

 

 

(166,697)

 

 

 

284,210

Other current liabilities

 

 

(967,999)

 

 

 

77,442

 

 

(98,521)

 

 

(44,750)

 

 

 

251,212

EBITDA

 

$

7,445,373

 

 

$

(343,910)

 

$

(4,204,120)

 

$

(741,344)

 

 

$

4,566,343

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,685,938

 

 

965,907

 

 

 

 —

Unit‑based compensation

 

 

135,692

 

 

 

50,422

 

 

302,530

 

 

151,265

 

 

 

135,692

Adjusted EBITDA

 

$

7,581,065

 

 

$

(293,488)

 

$

784,348

 

$

375,828

 

 

$

4,702,035

 

Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor

Our Predecessor’s historical financial condition and results of operations may not be comparable, either from period to period or going forward, to the Partnership’s future results of operations, for the reasons described below:

No Effect Given to Transactions in connection with Initial Public Offering

The historical financial statements of our Predecessor included in this Quarterly Report do not reflect the financial condition or results of operations of the Partnership. Further, these historical financial statements do not give effect to the transactions that were completed in connection with the closing of the Partnership’s IPO. In connection with our IPO, our Predecessor assigned all of its non‑operating working interests to an affiliate that was not contributed to us and the member of our Predecessor contributed all of its membership interests in Rivercrest to us in exchange for common units and a portion of the net proceeds from the IPO. In addition, the Contributing Parties directly or indirectly contributed to us the other assets that make up our initial assets in exchange for common units and a portion of the net proceeds from the IPO. The combination of the assets contributed to us by the Contributing Parties was accounted for at fair value as asset acquisitions. The fair value of the purchase consideration was based upon the value of the common units purchased in the Partnership’s IPO by third-party investors.

The historical financial data of our Predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the Partnership and may not provide an accurate indication of what our actual results would have been if these transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

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Impairment of Oil and Natural Gas Properties

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.

No impairment expense was recorded for the period from February 8, 2017 to June 30, 2017.  The substantial majority of our proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO.  In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the U.S. Securities and Exchange Commission (“SEC”) to exclude the properties acquired at the closing of the IPO from the ceiling test calculation.  This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through all financial reporting periods through December 31, 2017.  A component of the exemption received from the SEC is that we are required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate.  As of June 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate.  In making this determination, we considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors.  Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO and management affirmed that there has not been a material change to the fair value of these acquired assets since the IPO.  The properties acquired at the closing of our IPO have an unamortized cost at June 30, 2017 of $244.4 million.  Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $82.3 million for the period ending June 30, 2017.  We will continue to assess the fair value of the acquired assets at each periodic reporting date to ensure inclusion in the ceiling calculation is not required through the December 31, 2017 reporting period, which is the period of the exemption extended by the SEC.  Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired.   

During the six months ended June 30, 2016, our Predecessor recorded non-cash impairment charges of approximately $4.7 million primarily due to changes in reserve values resulting from the drop in commodity prices and other factors. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are taken.

Credit Agreements

In connection with our IPO, we entered into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders).  As of June 30, 2017, we had borrowed $18.3 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC and the acquisition of mineral and royalty interests underlying 1,116,874 gross acres (6,881 net royalty acres) for an aggregate purchase price of approximately $16.8 million.  For the period from February 8, 2017 to June 30, 2017, we incurred $243,127 in interest expense.

In January 2014, our Predecessor entered into a credit agreement with Frost Bank, as lender. For the six months ended June 30, 2016 and the period from January 1, 2017 to February 7, 2017, our Predecessor’s interest expense was

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$210,485 and $39,307, respectively. Our Predecessor had outstanding borrowings of $10.6 million as of December 31, 2016 and $10.6 million as of February 7, 2017.  We did not assume any indebtedness of our Predecessor in connection with the IPO.

Acquisition Opportunities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from our Sponsors, the Contributing Parties and third parties. We also may pursue acquisitions jointly with our Sponsors and the Contributing Parties. As a consequence of any such acquisition and acquisition‑related expense, the historical financial statements of our Predecessor will differ from our financial statements in the future.

Management Services Agreements

In connection with our IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective service agreements, affiliates of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective service agreements will reduce the amount of cash available for distribution to our unitholders.

Non‑Operated Working Interest Assignment

Prior to the transactions that were completed in connection with the IPO of the Partnership, our Predecessor assigned its non‑operated working interests and associated asset retirement obligations to an affiliated entity that was not contributed to the Partnership. As of the closing of its IPO and through the date of this Quarterly Report, the Partnership does not own any working interests and does not have any asset retirement obligations or any lease operating expenses as a working interest owner.

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Results of Operations

The following table summarizes our Predecessor’s and our revenue and expenses and production data for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Results of Operations (Unaudited)

 

 

For the period from February 8, 2017 to June 30, 

 

 

For the period from January 1, 2017 to February 7,

 

For the six months ended June 30, 

 

For the three months ended June 30, 

 

 

For the three months ended June 30, 

 

    

2017

  

  

2017

    

2016

    

2016

  

  

2017

Operating Results:

 

 

 

 

 

(Predecessor)

 

 

 

 

Oil, natural gas and NGL revenues

 

$

12,305,342

 

 

$

318,310

 

$

1,603,393

 

$

847,740

 

 

$

7,751,998

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes

 

 

823,787

 

 

 

19,651

 

 

83,252

 

 

48,211

 

 

 

617,681

Depreciation, depletion and accretion expense

 

 

6,667,377

 

 

 

113,639

 

 

825,054

 

 

349,440

 

 

 

4,131,717

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,685,938

 

 

965,907

 

 

 

 —

Marketing and other deductions

 

 

643,807

 

 

 

110,534

 

 

249,823

 

 

152,255

 

 

 

386,681

General and administrative expenses

 

 

3,392,375

 

 

 

532,035

 

 

788,500

 

 

422,711

 

 

 

2,181,293

Total costs and expenses

 

 

11,527,346

 

 

 

775,859

 

 

6,632,567

 

 

1,938,524

 

 

 

7,317,372

Operating income (loss)

 

 

777,996

 

 

 

(457,549)

 

 

(5,029,174)

 

 

(1,090,784)

 

 

 

434,626

Interest expense

 

 

243,127

 

 

 

39,307

 

 

210,485

 

 

105,197

 

 

 

182,975

Income (loss) before income taxes

 

 

534,869

 

 

 

(496,856)

 

 

(5,239,659)

 

 

(1,195,981)

 

 

 

251,651

State income taxes

 

 

 —

 

 

 

 —

 

 

9,189

 

 

3,304

 

 

 

 —

Net income (loss)

 

$

534,869

 

 

$

(496,856)

 

$

(5,248,848)

 

$

(1,199,285)

 

 

$

251,651

Production Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

 

159,274

 

 

 

3,696

 

 

27,796

 

 

13,441

 

 

 

99,763

Natural gas (Mcf)

 

 

1,316,598

 

 

 

32,961

 

 

249,284

 

 

115,448

 

 

 

826,927

Natural gas liquids (Bbls)

 

 

62,436

 

 

 

1,220

 

 

12,608

 

 

5,661

 

 

 

41,506

Combined volumes (Boe) (6:1)

 

 

441,143

 

 

 

10,410

 

 

81,951

 

 

38,343

 

 

 

279,090

 

Comparison of the Three Months Ended June 30, 2017 to the Three Months Ended June 30, 2016

The period presented for the three months ended June 30, 2017 and 2016 includes the results of operations of the Partnership and our Predecessor, respectively.  The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

Oil, Natural Gas and Natural Gas Liquids Revenues

For the three months ended June 30, 2017, our revenues were $7.8 million, an increase of $6.9 million, from $0.9 million for the three months ended June 30, 2016. The increase in revenues was primarily due to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests. 

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Our Predecessor’s and our revenues are a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes. The production volumes were 279,090 Boe or 3,067 Boe/d, for the three months ended June 30, 2017, an increase of 240,746 Boe or 2,646 Boe/d, from 38,343 Boe or 421 Boe/d, for the three months ended June 30, 2016.  The production realized from the overriding royalty interests we acquired from Maxus Energy Corporation in late April 2017 enabled us to offset natural production declines from our existing portfolio and to exit the quarter ended June 30, 2017 with slightly higher production.  Our average production per day for the month ended June 30, 2017 was 3,116 Boe/d, versus 3,025 Boe/d for the month ended March 31, 2017.

Our operators received an average of $45.10 per Bbl of oil, $2.89 per Mcf of natural gas and $20.83 per Bbl of natural gas liquids for the volumes sold during the three months ended June 30, 2017.  Our Predecessor’s operators received an average of $41.95 per Bbl of oil, $1.84 per Mcf of natural gas and $12.70 per Bbl of natural gas liquids for the volumes sold during the three months ended June 30, 2016.  The three months ended June 30, 2017 increased 7.5% or $3.15 per Bbl of oil and 57.3% or $1.05 per Mcf of natural gas as compared to the three months ended June 30, 2016.  These increases are consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 5.8% or $2.64 per Bbl of oil and 43.3% or $0.93 per Mcf of natural gas for the comparable periods. 

Production and Ad Valorem Taxes

Our production and ad valorem taxes for the three months ended June 30, 2017 were $617,681, an increase of $569,470 from $48,211 in the three months ended June 30, 2016.  The increase in production and ad valorem taxes was attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.

Depreciation, Depletion and Accretion Expense

Our depreciation, depletion and accretion expense for the three months ended June 30, 2017 was $4.1 million, an increase of $3.8 million from our Predecessor’s depreciation, depletion and accretion expense of $0.3 million for the three months ended June 30, 2016.  The increase in the depreciation, depletion and accretion expense was primarily attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired properties.  

Our average depletion rate per barrel was $14.66 for the three months ended June 30, 2017, an increase of $5.60 per barrel from $9.06 average depletion rate per barrel for the three months ended June 30, 2016.  The increase in the average depletion rate per barrel was primarily attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired properties.  Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units‑of‑production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

No impairment expense was recorded for the three months ended June 30, 2017.  The substantial majority of our proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO.  In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation.  This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through all financial reporting periods through December 31, 2017.  A component of the exemption received from the SEC is that we are required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate.  As of June 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, we considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors.  Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the

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date of the IPO and management affirmed that there has not been a material change to the fair value of these acquired assets since the IPO.  The properties acquired at the closing of our IPO have an unamortized cost at June 30, 2017 of $244.4 million.  Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $82.3 million for the period ending June 30, 2017.  We will continue to assess the fair value of the acquired assets at each periodic reporting date to ensure inclusion in the ceiling calculation is not required through the December 31, 2017 reporting period, which is the period of the exemption extended by the SEC.  Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired. 

Impairments for our Predecessor totaled $1.0 million for the three months ended June 30, 2016 primarily due to the impact that declines in commodity prices had on the value of reserve estimates.

Marketing and Other Deductions

Our marketing and other deductions includes product marketing expense, which is a post‑production expense, and our Predecessor’s marketing and other deductions also includes lease operating expenses related to its non‑operated working interests. Marketing and other deductions for the three months ended June 30, 2017 were $0.4 million, an increase of $0.2 million from our Predecessor’s marketing and other deductions for the three months ended June 30, 2016 of $0.2 million.  The increase in marketing and other deductions was attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.

General and Administrative Expenses

Our Predecessor’s and our general and administrative expenses for the three months ended June 30, 2017 were $2.2 million, an increase of $1.8 million from our Predecessor’s general and administrative expenses of $0.4 million for the three months ended June 30, 2016.  The increase in general and administrative expenses was attributable to the increased cost related to operating the Partnership as a publicly traded company.

Interest Expense

Our interest expense for the three months ended June 30, 2017 was $0.2 million as compared to our Predecessor’s interest expense of $0.1 million for the three months ended June 30, 2016. 

Comparison of the Six Months Ended June 30, 2017 to the Six Months Ended June 30, 2016

The period presented for the six months ended June 30, 2017 includes the results of operations of our Predecessor for the period from January 1, 2017 to February 7, 2017 and our results of operations for the period from February 8, 2017 to June 30, 2017.  The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

Oil, Natural Gas and Natural Gas Liquids Revenues

For the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017, our Predecessor’s and our revenues were $0.3 and $12.3 million, respectively, for combined revenues of $12.6 million for the six months ended June 30, 2017, an increase of $11.0 million, from $1.6 million for the six months ended June 30, 2016. The increase in revenues was primarily due to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests. 

Our Predecessor’s and our revenues are a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes. The production volumes were 10,410 Boe or 274 Boe/d and 441,143 Boe or 3,085 Boe/d, for the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017, respectively.  The combined production for the six months ended June 30, 2017 was 451,552 Boe or 2,495 Boe/d, an increase of 369,601 Boe or 2,044 Boe/d, from 81,951 Boe or 450 Boe/d, for the six months ended June 30, 2016.  The production realized from the overriding royalty interests we acquired from Maxus Energy Corporation in late April 2017

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enabled us to offset natural production declines from our existing portfolio and to exit the quarter ended June 30, 2017 with slightly higher production.  Our average production per day for the month ended June 30, 2017 was 3,116 Boe/d, versus 3,025 Boe/d for the month ended March 31, 2017. 

Our Predecessor’s operators received an average of $47.04 per Bbl of oil, $3.47 per Mcf of natural gas and $24.61 per Bbl of natural gas liquids for the volumes sold during the period from January 1, 2017 to February 7, 2017.  Our operators received an average of $45.94 per Bbl of oil, $2.76 per Mcf of natural gas and $21.67 per Bbl of natural gas liquids for the volumes sold during the period from February 8, 2017 to June 30, 2017.  For the combined six months ended June 30, 2017, the operators received an average of $45.97 per Bbl of oil, $2.78 per Mcf of natural gas and $21.73 per Bbl of natural gas liquids for the volumes sold.  Our Predecessor’s operators received an average of $36.14 per Bbl of oil, $1.78 per Mcf of natural gas and $12.33 per Bbl of natural gas liquids for the volumes sold during the six months ended June 30, 2016.  Average prices received by the operators during the combined six months ended June 30, 2017 increased 27.2% or $9.83 per Bbl of oil and 56.2% or $1.00 per Mcf of natural gas as compared to the six months ended June 30, 2016.  These increases are consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 9.7% or $4.39 per Bbl of oil and 47.3% or $0.98 per Mcf of natural gas for the comparable periods. 

Production and Ad Valorem Taxes

Our production and ad valorem taxes for the period from January 1, 2017 to February 7, 2017 and the period February 8, 2017 to June 30, 2017 were $19,651 and $823,787, respectively.  The combined production and ad valorem taxes for the six months ended June 30, 2017 were $843,438, an increase of $760,186 from $83,252 in the six months ended June 30, 2016.  The increase in production and ad valorem taxes was attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.

Depreciation, Depletion and Accretion Expense

Our Predecessor’s and our depreciation, depletion and accretion expense for the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017 was $0.1 million and $6.7 million respectively for a combined expense of $6.8 million for the six months ended June 30, 2017.  This was an increase of $6.0 million from our Predecessor’s depreciation, depletion and accretion expense of $0.8 million for the six months ended June 30, 2016.  The increase in the depreciation, depletion and accretion expense was primarily attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired properties.  

Our Predecessor’s and our average depletion rate per barrel was $10.31 and $14.96 for the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017, respectively.  The combined average depletion rate per barrel for the six months ended June 30, 2017 was $14.86, an increase of $4.84 per barrel from an average depletion rate of $10.02 per barrel for the six months ended June 30, 2016.  The increase in the average depletion rate per barrel was primarily attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired properties.  Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units‑of‑production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

No impairment expense was recorded for the period from February 8, 2017 to June 30, 2017.  The substantial majority of our proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO.  In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the SEC to exclude the recently acquired properties from the ceiling test calculation.  This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through all financial reporting periods through December 31, 2017.  A component of the exemption received

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from the SEC is that we are required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate.  As of June 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, we considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors.  Additionally, the fair value of the properties acquired at the closing of the IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO and management has affirmed that there has not been a material change to the fair value of these acquired assets since the IPO.  The properties acquired at the closing of our IPO have an unamortized cost at June 30, 2017 of $244.4 million.  Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $82.3 million for the period ending June 30, 2017.  We will continue to assess the fair value of the acquired assets at each periodic reporting date to ensure inclusion in the ceiling calculation is not required through the December 31, 2017 reporting period, which is the period of the exemption extended by the SEC.  Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired. 

Impairments for our Predecessor totaled $3.7 million for the six months ended June 30, 2016 primarily due to the impact that declines in commodity prices had on the value of reserve estimates.

Marketing and Other Deductions

Our marketing and other deductions includes product marketing expense, which is a post‑production expense, and our Predecessor’s marketing and other deductions also includes lease operating expenses related to its non‑operated working interests. Marketing and other deductions for the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017 were $0.1 million and $0.6 million, respectively.  The combined marketing and other deductions for the six months ended June 30, 2017 were $0.8 million, an increase of $0.5 million from our Predecessor’s marketing and other deductions for the six months ended June 30, 2016 of $0.3 million.  The increase in marketing and other deductions was attributable the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.

General and Administrative Expenses

Our Predecessor’s and our general and administrative expenses for the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017 were $0.5 million and $3.4 million, respectively.  General and administrative expenses for the combined six months ended June 30, 2017 were $3.9 million, an increase of $3.1 million from our Predecessor’s general and administrative expenses of $0.8 million for the six months ended June 30, 2016.  The increase in general and administrative expenses was attributable to the increased costs related to operating the Partnership as a publicly traded company.

Interest Expense

Our Predecessor’s and our interest expense for the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017 was $39,307 and $243,127, respectively. The interest expense for the combined six months ended June 30, 2017 was $0.3 million as compared to our Predecessor’s interest expense of $0.2 million for the six months ended June 30, 2016. 

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations and equity and debt financings and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. We have entered into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million

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(subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), to initially be used for general partnership purposes, including working capital, acquisitions and certain IPO-related transaction expenses. In connection with the August 1 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million.   Aggregate commitments remain at $50.0 million, providing for maximum availability under the secured revolving credit facility of $50.0 million.  As of August 7, 2017, we had an outstanding balance of $18.3 million under our secured revolving credit facility.

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash.” Available cash for each quarter will be determined by the board of directors of our general partner (the “Board of Directors”) following the end of such quarter. We expect that available cash for each quarter will generally equal or approximate our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs, including replacement or growth capital expenditures, that the Board of Directors may determine is appropriate.

Unlike a number of other master limited partnerships, we do not generally intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. If they believe it is warranted, the Board of Directors may withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the period(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise reserve cash for distributions, or to incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

Because our partnership agreement requires us to distribute an amount equal to all available cash we generate each quarter, our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and natural gas liquids, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of our quarterly distributions may be significant and could result in our not making any distribution for any particular quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The Board of Directors may change our distribution policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters.

On May 2, 2017, the Board of Directors declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017.  The Partnership’s calculated cash available for distribution was $0.18 per common unit for the quarter.  However, during the period ended March 31, 2017, pursuant to the contribution agreement entered into by the Contributing Parties prior to the IPO, the Partnership received cash from the Contributing Parties for oil, natural gas and natural gas liquids production for periods prior to the IPO.  The Board of Directors voted to distribute an additional $0.05 per common unit.  The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017.  The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

 

On July 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017.  The Partnership’s calculated cash available for distribution was $0.28 per common unit for

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the quarter.  The Board of Directors voted to distribute an additional $0.02 per common unit due to excess working capital generated primarily from positive prior period production from our operators.  The distribution will be paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017. 

 

Cash Flows

The following table presents our cash flows and our Predecessor’s cash flows for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flows

 

 

 

(in thousands)

 

 

 

For the period from February 8, 2017 to June 30, 

 

 

For the period from January 1, 2017 to February 7,

 

For the six months ended June 30, 

 

 

    

2017

  

  

2017

    

2016

 

Cash Flow Data:

 

 

 

 

 

(Predecessor)

 

Cash flows provided by operating activities

 

$

8,578

 

 

$

187

 

$

550

 

Cash flows used in investing activities

 

 

(113,202)

 

 

 

(1)

 

 

(79)

 

Cash flows provided by (used in) financing activities

 

 

110,451

 

 

 

 —

 

 

(263)

 

Net increase in cash

 

$

5,827

 

 

$

186

 

$

208

 

 

Operating Activities

Our Predecessor’s and our operating cash flow is impacted by many variables, the most significant of which is the change in prices for oil, natural gas and natural gas liquids. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our and our Predecessor’s control and are difficult to predict.  Cash flows provided by operating activities for the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017 were $0.2 million and $8.6 million, respectively.  Cash flows provided by operating activities for the combined six months ended June 30, 2017 were $8.8 million, an increase of $8.2 million compared to our Predecessor’s cash flows provided by operating activities of $0.6 million for the six months ended June 30, 2016.  The increase was largely attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.

Investing Activities

Cash flows used in investing activities for the period from January 1, 2017 to February 7, 2017 and the period from February 8, 2017 to June 30, 2017, were $523 and $113.2 million, respectively.  The cash flows used in investing activities for the combined six months ended June 30, 2017 were $113.2 million, an increase of $113.1 million compared to our Predecessor’s cash flows used in investing activities for the six months ended June 30, 2016 of $0.1 million.  For the period from February 8, 2017 to June 30, 2017, we used the $96.2 million in proceeds received from our IPO to pay the cash portion of our acquisition of oil and natural gas properties at the IPO and we used $16.8 million in the acquisition of mineral and royalty interests underlying 1,116,874 gross acres (6,881 net royalty acres).

Financing Activities

Our Predecessor did not have any cash flows used in or provided by financing activities for the period from January 1, 2017 to February 7, 2017.  Cash flows provided by financing activities was $110.5 million for the period from February 8, 2017 to June 30, 2017 as compared to our Predecessor’s cash used in financing activities of $0.3 million for the six months ended June 30, 2016.   During the period from February 8, 2017 to June 30, 2017, we received $96.2 million in proceeds from our IPO, we borrowed $18.3 million, paid a distribution to unitholders of $3.8 million and paid loan origination costs of $0.3 million. During the six months ended June 30, 2016, our Predecessor re-paid $0.3 million on their long‑term debt.

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Capital Expenditures

During the period from January 1, 2017 to February 7, 2017, our Predecessor spent $523 on additional lease and well equipment and intangible drilling costs related to the Predecessor’s working interests and office equipment.  During the period from February 8, 2017 to June 30, 2017, we acquired mineral and royalty interests from the Contributing Parties for common units with a total value at the IPO of $169.1 million and $96.2 million in cash.  Additionally, we spent an aggregate amount of $16.8 million for the acquisition of mineral and royalty interests underlying 1,116,874 gross acres (6,881 net royalty acres).    During the six months ended June 30, 2016, our Predecessor spent $20,417 on additional lease and well equipment and intangible drilling costs related to the Predecessor’s working interests and office equipment.

Indebtedness

New Revolving Credit Agreement

We entered into a $50.0 million revolving credit facility in connection with our IPO, which is secured by substantially all of our assets and the assets of our wholly owned subsidiaries. Under the secured revolving credit facility, availability under the facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will be re-determined semi-annually on February 1 and August 1 of each year based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries. The secured revolving credit facility permits aggregate commitments under the facility to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.  In connection with the August 1 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million.  Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0 million.

The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facility also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control. As of August 7 , 2017, we have borrowed $18.3 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC and the acquisition of mineral and royalty interests underlying 1,116,874 gross acres (6,881 net royalty acres) for an aggregate purchase price of approximately $16.8 million. 

Predecessor Credit Facility

Our Predecessor entered into a credit agreement with Frost Bank for up to $50.0 million. The credit facility was subject to borrowing base restrictions and was collateralized by certain properties. The borrowing base was $20 million with interest payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans. As of December 31, 2016, our Predecessor’s total indebtedness on its credit agreement was approximately $10.6 million with an average interest rate of 3.39%. The loan was to mature in January 2018. The credit facility contained certain restrictive covenants. As of December 31, 2016, the Predecessor was in compliance with all of the covenants included in the credit facility. On February 8, 2017, our Predecessor repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the sale of our Predecessor’s mineral and royalty and overriding royalty interests to the Partnership. We did not assume any indebtedness of our Predecessor in connection with the IPO.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes‑Oxley Act of 2002 (“Sarbanes-Oxley Act”), and are therefore not required to make a formal assessment of the effectiveness of

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our internal controls over financial reporting for that purpose. We are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes‑Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2018. To comply with the requirements of being a public company, we will need to implement additional controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm is not yet required to attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the Jumpstart Our Business Act (“JOBS Act”) or as long as we are a non‑accelerated filer.

New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. However, we chose to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non‑emerging growth companies. Our election to “opt out” of the extended transition period is irrevocable.

The effects of new accounting pronouncements are discussed in Note 2‑Summary of Significant Accounting Policies within the historical financial statements included elsewhere in this Quarterly Report.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon the historical financial statements of our Predecessor, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

See the notes to our Predecessor’s and our historical financial statements included elsewhere in this Quarterly Report for additional information regarding these accounting policies.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our Predecessor’s or our results of operations for the period from January 1, 2016 through June 30, 2017.

Off‑Balance Sheet Arrangements

As of June 30, 2017, neither we, nor our Predecessor had any off‑balance sheet arrangements other than operating leases.  As of June 30, 2017, there have been no significant changes to our contractual obligations previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016.

Corporate Governance

 

We have adopted governance guidelines to assist the Board of Directors in the exercise of its responsibilities. Our governance guidelines and our audit committee charter are posted on the “Corporate Governance” section of our website, located at www.kimbellrp.investorroom.com/corporate-governance.

 

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Our corporate governance guidelines provide that the non-management directors will meet periodically in executive sessions without management participation. At least annually, all of the independent directors of the Board of Directors meet in executive sessions without management participation or participation by non-independent directors. Currently, the chairman of the Audit Committee of the Board of Directors presides at the executive sessions of the executive sessions of the independent directors.

 

Interested parties may communicate directly with the independent members of the Board of Directors by submitting in an envelope marked “Confidential” addressed to the “Independent Members of the Board” in care of the Secretary of the general partner at:

 

Kimbell Royalty Partners, LP

777 Taylor Street, Suite 810

Fort Worth, TX  76102

 

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and natural gas liquids production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and natural gas liquids production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.  Currently, we do not have any commodity hedges in place but may do so in the future if the Board of Directors decides doing so is in the best interest of the Partnership.

Credit Risk

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and natural gas liquids produced and sold from the underlying properties.  It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of June 30, 2017, we had total borrowings outstanding under our secured revolving credit facility of $18.3 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 $0.2 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.

 

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a‑15(b) under the Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a‑15(e) and 15d‑15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2017.

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Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition, cash flows or results of operations.

 

Item 1A. Risk Factors

 

In addition to the other information set forth in this report, you should carefully consider the risks under the heading “Risk Factors” in our 2016 Annual Report on Form 10-K and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

 

Item 5. Other Information

 

On August 9, 2017, the Board of Directors, upon the advice and recommendation of the Compensation and Conflicts Committee of the Board of Directors, approved a form of Director Unit Agreement (the “Unit Agreement”) to be used in connection with grants to be made under the LTIP.  The Unit Agreement contemplates that the common units subject to each individual grant will be fully vested as of the grant date.

 

In connection with the approval of the Unit Agreement, the Board of Directors approved the grant and issuance of common units to each of the Partnership’s non-employee directors, William H. Adams III, C.O. Ted Collins, Jr., Benny D. Duncan, T. Scott Martin and Craig Stone, in an amount equal to $30,000 divided by the average trading price of the Partnership’s common units on the date of grant.  The Board of Directors also approved the grant and issuance of restricted units to certain consultants of the general partner pursuant to a form of restricted unit agreement previously approved by the Board of Directors.

 

Item 6. Exhibits

 

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report and is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

 

 

 

    

Kimbell Royalty Partners, LP

 

 

 

 

 

By:

Kimbell Royalty GP, LLC

 

 

 

its general partner

 

 

 

Date: August 11, 2017

 

By:

/s/ Robert D. Ravnaas

 

 

 

Name:

Robert D. Ravnaas

 

 

 

Title:

Chief Executive Officer and Chairman

 

 

 

 

Principal Executive Officer

 

 

 

 

 

 

Date: August 11, 2017

 

By:

/s/ R. Davis Ravnaas

 

 

 

Name:

R. Davis Ravnaas

 

 

 

Title:

President and Chief Financial Officer

 

 

 

 

Principal Financial Officer

 

 

 

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EXHIBIT INDEX

Exhibit

Number

 

Description

3.1

Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017) 

3.2

First Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners LP, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Form 8‑K filed on February 14, 2017)

3.3

Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017)

3.4

First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Form 8‑K filed on February 14, 2017)

10.1

Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Form 8-K filed on May 11, 2017)

10.2*

Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Director Unit Agreement

31.1*

Certification of Chief Executive Officer pursuant to Rule 13a‑14(a)/15d‑14(a) under the Securities Exchange Act of 1934

31.2*

Certification of Chief Financial Officer pursuant to Rule 13a‑14(a)/15d‑14(a) under the Securities Exchange Act of 1934

32.1**

Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350

32.2**

Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350

101.INS**

XBRL Instance Document.

101.SCH**

XBRL Taxonomy Extension Schema Document

101.CAL**

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB**

XBRL Taxonomy Extension Label Linkbase Document

101.PRE**

XBRL Taxonomy Extension Presentation Linkbase Document


*      —filed herewith

**    —furnished herewith

 —management contract or compensatory plan or arrangement

 

 

 

 

 

 

 

 

 

 

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