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Kimbell Royalty Partners, LP - Quarter Report: 2017 September (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 September 30, 2017

OR

 

 

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 November 8, 2017, 16,509,799 common units of the registrant were outstanding.

 

 

 


 

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

FORM 10‑Q

TABLE OF CONTENTS

 

 

PART I – FINANCIAL INFORMATION

Item 1.     Consolidated Financial Statements (Unaudited) 

1

Consolidated Balance Sheets 

1

Consolidated Statements of Operations  

2

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

3

Consolidated Statements of Cash Flows  

4

Notes to Consolidated Financial Statements 

5

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

16

Item 3.     Quantitative and Qualitative Disclosures About Market Risk 

31

Item 4.     Controls and Procedures 

31

 

 

 

 

PART II – OTHER INFORMATION 

 

Item 1.     Legal Proceedings 

32

Item 1A.  Risk Factors 

32

Item 6.     Exhibits  

32

Signatures 

34

 

 

 

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Table of Contents

PART I – FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

September 30, 

 

 

December 31, 

 

 

2017

 

  

2016

ASSETS

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

6,226,479

 

 

$

505,880

Oil, natural gas and NGL receivables

 

 

5,501,513

 

 

 

474,103

Other current assets

 

 

258,785

 

 

 

344,368

Total current assets

 

 

11,986,777

 

 

 

1,324,351

Property and equipment, net

 

 

204,343

 

 

 

261,568

Oil and natural gas properties

 

 

 

 

 

 

 

Oil and natural gas properties, using full-cost method of accounting

 

 

285,043,287

 

 

 

70,888,121

Less: accumulated depreciation, depletion, accretion and impairment

 

 

(11,047,641)

 

 

 

(51,948,355)

Total oil and natural gas properties

 

 

273,995,646

 

 

 

18,939,766

Deposits on oil and natural gas properties

 

 

3,949,000

 

 

 

 —

Loan origination costs, net

 

 

270,833

 

 

 

13,046

Total assets

 

$

290,406,599

 

 

$

20,538,731

 

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS' CAPITAL (PREDECESSOR MEMBERS' EQUITY)

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

Accounts payable

 

$

152,569

 

 

$

1,030,862

Other current liabilities

 

 

2,146,834

 

 

 

112,508

Asset retirement obligations

 

 

 —

 

 

 

27,013

Total current liabilities

 

 

2,299,403

 

 

 

1,170,383

Asset retirement obligations

 

 

 —

 

 

 

14,468

Other liabilities

 

 

 —

 

 

 

123,158

Long-term debt

 

 

22,214,090

 

 

 

10,598,860

Total liabilities

 

 

24,513,493

 

 

 

11,906,869

Commitments and contingencies

 

 

 

 

 

 

 

Predecessor members' equity

 

 

 —

 

 

 

8,631,862

Partners' capital

 

 

265,893,106

 

 

 

 —

Total liabilities and partners' capital (predecessor members' equity)

 

$

290,406,599

 

 

$

20,538,731

 

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

 

 

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Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

Partnership

 

 

Predecessor

 

 

Three Months Ended September 30, 

 

 

Three Months Ended September 30, 

 

Period from February 8, 2017 to September 30, 

 

 

Period from January 1, 2017 to February 7,

 

Nine Months Ended September 30, 

 

 

2017

  

  

2016

 

2017

  

  

2017

    

2016

Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL revenues

 

$

8,351,399

 

 

$

969,084

 

$

20,656,741

 

 

$

318,310

 

$

2,572,477

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes

 

 

778,733

 

 

 

120,315

 

 

1,602,520

 

 

 

19,651

 

 

203,567

Depreciation, depletion and accretion expense

 

 

4,488,915

 

 

 

418,969

 

 

11,156,292

 

 

 

113,639

 

 

1,244,023

Impairment of oil and natural gas properties

 

 

 —

 

 

 

306,959

 

 

 —

 

 

 

 —

 

 

4,992,897

Marketing and other deductions

 

 

424,702

 

 

 

320,698

 

 

1,068,509

 

 

 

110,534

 

 

570,521

General and administrative expense

 

 

2,314,718

 

 

 

463,501

 

 

5,707,093

 

 

 

532,035

 

 

1,252,001

Total costs and expenses

 

 

8,007,068

 

 

 

1,630,442

 

 

19,534,414

 

 

 

775,859

 

 

8,263,009

Operating income (loss)

 

 

344,331

 

 

 

(661,358)

 

 

1,122,327

 

 

 

(457,549)

 

 

(5,690,532)

Other expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

225,302

 

 

 

103,596

 

 

468,429

 

 

 

39,307

 

 

314,081

Income (loss) before income taxes

 

 

119,029

 

 

 

(764,954)

 

 

653,898

 

 

 

(496,856)

 

 

(6,004,613)

State income taxes

 

 

 —

 

 

 

4,212

 

 

 —

 

 

 

 —

 

 

13,401

Net income (loss)

 

$

119,029

 

 

$

(769,166)

 

$

653,898

 

 

$

(496,856)

 

$

(6,018,014)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.01

 

 

$

(1.27)

 

$

0.04

 

 

$

(0.82)

 

$

(9.96)

Diluted

 

$

0.01

 

 

$

(1.27)

 

$

0.04

 

 

$

(0.82)

 

$

(9.96)

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

16,337,985

 

 

 

604,137

 

 

16,334,774

 

 

 

604,137

 

 

604,137

Diluted

 

 

16,503,664

 

 

 

604,137

 

 

16,434,385

 

 

 

604,137

 

 

604,137

 

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 (Partnership)

 

 

 —

 

 

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

 

 

 —

 

 

(8,705,333)

 

 

 

 

 

 

 

Unit-based compensation

 

 

177,091

 

 

569,889

 

 

 

 

 

 

 

Net income

 

 

 —

 

 

653,898

 

 

 

 

 

 

 

Partners' capital - September 30, 2017

 

 

16,509,799

 

$

265,893,106

 

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)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to September 30, 

 

 

Period from January 1, 2017 to February 7,

 

Nine Months Ended September 30, 

 

    

2017

  

  

2017

    

2016

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

653,898

 

 

$

(496,856)

 

$

(6,018,014)

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

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion and accretion expense

 

 

11,156,292

 

 

 

113,639

 

 

1,244,023

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,992,897

Amortization of loan origination costs

 

 

41,667

 

 

 

4,241

 

 

34,245

Amortization of tenant improvement allowance

 

 

 —

 

 

 

(2,864)

 

 

(25,777)

Unit-based compensation

 

 

569,889

 

 

 

50,422

 

 

453,795

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL receivables

 

 

(496,886)

 

 

 

14,551

 

 

11,258

Other current assets

 

 

(258,785)

 

 

 

333,056

 

 

1,246,269

Accounts payable

 

 

152,569

 

 

 

247,972

 

 

(1,071,453)

Other current liabilities

 

 

2,146,834

 

 

 

(77,442)

 

 

89,550

Net cash provided by operating activities

 

 

13,965,478

 

 

 

186,719

 

 

956,793

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

Purchases of property and equipment

 

 

(57,592)

 

 

 

 —

 

 

(18,016)

Deposits on oil and natural gas properties

 

 

(3,949,000)

 

 

 

 —

 

 

 —

Purchase of oil and natural gas properties

 

 

(113,183,664)

 

 

 

(523)

 

 

(75,883)

Net cash used in investing activities

 

 

(117,190,256)

 

 

 

(523)

 

 

(93,899)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

Proceeds from initial public offering

 

 

96,255,000

 

 

 

 —

 

 

 —

Distributions to unitholders

 

 

(8,705,333)

 

 

 

 —

 

 

 —

Borrowings on long-term debt

 

 

22,214,090

 

 

 

 —

 

 

 —

Repayments on long-term debt

 

 

 —

 

 

 

 —

 

 

(550,000)

Payment of loan origination costs

 

 

(312,500)

 

 

 

 —

 

 

(13,000)

Net cash provided by (used in) financing activities

 

 

109,451,257

 

 

 

 —

 

 

(563,000)

NET INCREASE IN CASH AND CASH EQUIVALENTS

 

 

6,226,479

 

 

 

186,196

 

 

299,894

CASH AND CASH EQUIVALENTS, beginning of period

 

 

 —

 

 

 

505,880

 

 

379,741

CASH AND CASH EQUIVALENTS, end of period

 

$

6,226,479

 

 

$

692,076

 

$

679,635

Supplemental cash flow information:

 

 

 

 

 

 

 

 

 

 

Cash paid for interest

 

$

276,246

 

 

$

34,505

 

$

280,010

Cash paid for taxes

 

$

 —

 

 

$

5,355

 

$

17,468

Non-cash investing and financing activities:

 

 

 

 

 

 

 

 

 

 

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

(Unaudited)

 

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “the 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,” 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.

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 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 making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing 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 periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of the Predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. The mineral and royalty interests underlying the oil, natural gas and natural gas liquids (“NGL”) 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 Company, L.P. (“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 NGL 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 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.

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Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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 the unaudited consolidated 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 NGL 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 NGL 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 NGL 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 current assets include 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 is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. 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 September 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-

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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.

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 NGL 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 NGL 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 NGL 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.

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 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 September 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 September 30, 2017 of $240.8 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $78.4 million for the period ending September 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. All of the Partnership’s oil and natural gas properties are subject to the full-cost ceiling test. No impairment expense was recorded for the period from February 8, 2017 to September 30, 2017.

No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). The Predecessor recorded a full-cost ceiling impairment of $0.3 million and $5.0 million

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

for the three and nine months ended September 30, 2016, respectively, as a result of reductions in estimated proved reserves and 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 NGL 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 period from February 8, 2017 to September 30, 2017, the Predecessor 2017 Period, or the nine months ended September 30, 2016.

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

Other Current Liabilities

Other current liabilities consists of employee bonus accrual, ad valorem taxes and revenue processing fees.

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 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. The Partnership and the Predecessor incurred de minimis amounts of state income taxes during 2017.

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 September 30, 2017 and December 31, 2016, respectively.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The Partnership and the Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to September 30, 2017, the Predecessor 2017 Period, and the nine months ended September 30, 2016, the Partnership and the Predecessor 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 NGL produced and sold from its properties. It is believed that the loss of any single purchaser 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 NGLs from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and NGL 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 NGL produced and sold from the properties.

To the extent actual volumes and prices of oil, natural gas and NGLs 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 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 Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the accompanying unaudited 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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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 Predecessor 2017 Period.

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 and will be applied prospectively on or after the effective date. 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 is not expected to have a material impact on the Partnership’s financial statements or results of operations.

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 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.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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.

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 substantial completion of review of our contracts and analysis done so 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 historical accounting policies to the new standard. The Partnership will continue to monitor specific developments for our industry as it relates to ASU 2014-09. The Partnership anticipates using the modified retrospective method to adopt the new standard.

 

NOTE 3—ACQUISITIONS

In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million 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.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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 September 30, 2017, the Partnership’s outstanding balance was $22.2 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of September 30, 2017.

During the period ended September 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 September 30, 2017, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.51%.

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 base 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 Contributing Parties at the time of the IPO. On May 12, 2017, the Partnership issued 163,324 restricted units under the LTIP.

On May 2, 2017, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. 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.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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 was 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 of (i) common units in an amount equal to $30,000 to certain non-employee directors of the Partnership under the LTIP, which were fully vested as of the grant date, and (ii) a total of 4,247 restricted units to certain consultants under the LTIP. Such grants were made on August 11, 2017.

As of September 30, 2017, 16,509,799 common units of the Partnership were outstanding.

NOTE 6—EARNINGS (LOSS) PER UNIT

Basic earnings per unit (“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 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 Predecessor 2017 Period and the nine months ended September 30, 2016, the effect of the 110,000 options issued under the Predecessor’s long-term incentive plan were 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 those periods.

The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

Partnership

 

 

Predecessor

 

 

Three Months Ended September 30, 

 

 

Three Months Ended September 30, 

 

Period from February 8, 2017 to September 30, 

 

 

Period from January 1, 2017 to February 7,

 

Nine Months Ended September 30, 

 

 

2017

 

 

2016

 

2017

 

 

2017

 

2016

Net income (loss)

 

$

119,029

 

 

$

(769,166)

 

$

653,898

 

 

$

(496,856)

 

$

(6,018,014)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.01

 

 

$

(1.27)

 

$

0.04

 

 

$

(0.82)

 

$

(9.96)

Diluted

 

$

0.01

 

 

$

(1.27)

 

$

0.04

 

 

$

(0.82)

 

$

(9.96)

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

16,337,985

 

 

 

604,137

 

 

16,334,774

 

 

 

604,137

 

 

604,137

Diluted

 

 

16,503,664

 

 

 

604,137

 

 

16,434,385

 

 

 

604,137

 

 

604,137

 

 

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.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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 value of our common units on the respective grant date. The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs. The following table presents a summary of the Partnership’s unvested common units.

 

 

 

 

 

 

 

 

 

 

 

 

    

 

    

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

 

24,253

 

 

 

 

15.780

 

Granted - non-employee directors

 

9,520

 

 

 

 

 

15.780

 

 

Vested

 

(9,520)

 

 

 

 

 

Forfeited

 

 

 

 

 

 

Exercised

 

 

 

 

 

 

Unvested at September 30, 2017

 

167,571

 

$

18.655

 

$

15.780

 

1.616 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 Predecessor 2017 Period and the nine months ended September 30, 2016, total compensation expense for awards under the Predecessor’s long-term incentive plan was $50,422 and $453,795, respectively, and is included general and administrative expenses in the accompanying 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 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, the Partnership did not own any working interests and did not have any ARO or any lease operating expenses as a working interest owner.

 

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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 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 three months ended September 30, 2017, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $100,000, $100,000, $30,000, $125,884 and $164,616, respectively. During the period from February 8, 2017 to September 30, 2017, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $266,667, $266,667, $80,000, $335,691 and $438,975, 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 Predecessor 2017 Period and the nine months ended September 30, 2016, the Predecessor Company’s activities included certain related party receivables and payables; however, such amounts were de minimis at 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 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 September 30, 2017 in the preparation of its consolidated financial statements.

On October 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended September 30, 2017. The distribution will be paid on November 13, 2017 to unitholders of record as of the close of business on November 6, 2017.

On October 9, 2017, the Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility. The Partnership was required to pay a deposit, which is included in deposits on oil and natural gas properties in the accompanying unaudited consolidated balance sheet at September 30, 2017.

On November 8, 2017, the Partnership acquired mineral and royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price of approximately $7.3 million in various counties in Arkansas. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.

 

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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 consolidated 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 financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for periods on or prior to February 7, 2017 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(“NGL”) 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 of America (“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 NGL 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 September 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 September 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

In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million 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.

On October 9, 2017, the Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility. The Partnership was required to put down a deposit which is included in deposits on oil and natural gas properties in the accompanying unaudited consolidated balance sheet at September 30, 2017.

On November 8, 2017, the Partnership acquired mineral and royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price of approximately $7.3 million in various counties in Arkansas. The Partnership funded these acquisitions with borrowings under its secured 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 nine months ended September 30, 2017, West Texas Intermediate (“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 nine months ended September 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 nine months ended September 30, 2017, the Henry Hub spot market price of natural gas 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 nine months ended September 30, 2016, the Henry Hub spot market price of natural gas ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $3.19 per MMBtu on September 21, 2016. On October 30, 2017, the WTI posted price for crude oil was $54.11 per Bbl and the Henry Hub spot market price of natural gas was $2.94 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 and nine months ended September 30, 2017 and 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended September 30,

 

For the nine months ended September 30,

EIA Average Price:

 

2017

 

2016

 

2017

 

2016

Oil (Bbl)

 

$

48.18

 

$

44.85

 

$

49.30

 

$

41.35

Natural gas (MMBtu)

 

$

2.95

 

$

2.88

 

$

3.01

 

$

2.34

Source: EIA

Rig Count

The Baker Hughes U.S. Rotary Rig count was 940 active rigs at September 29, 2017, an 80% increase from 522 active rigs at September 30, 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 83% from 468 active rigs at September 30, 2016 to 857 active rigs at September 29, 2017. The active rig count across our acreage at October 31, 2017 totaled 21 rigs, a 40% increase compared to the 15 rigs 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 NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. For the three months ended September 30, 2017, our revenues were generated 57% from oil sales, 30% from natural gas sales, 11% from NGL sales and 2% from other sales. For the three months ended September 30, 2016, our Predecessor’s revenues were generated 60% from oil sales, 30% from natural gas sales and 10% from NGL sales. For

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the period from February 8, 2017 to September 30, 2017, our revenues were generated 59% from oil sales, 29% from natural gas sales, 11% from NGL sales and 1% from other sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined nine months ended September 30, 2017, the revenues were generated 58% from oil sales, 30% from natural gas sales, 11% from NGL sales and 1% from other sales. For the nine months ended September 30, 2016, our Predecessor’s revenues were generated 61% from oil sales, 29% from natural gas sales and 10% from NGL 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.

Neither we nor our Predecessor entered into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas and NGLs 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 NGLs, but we will not be protected against decreases in price, and if the price of oil, natural gas and NGLs 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 NGL 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.

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

Partnership

 

 

Predecessor

 

 

Three Months Ended September 30, 

 

 

Three Months Ended September 30, 

 

Period from February 8, 2017 to September 30, 

 

 

Period from January 1, 2017 to February 7,

 

Nine Months Ended September 30, 

 

 

2017

 

 

2016

 

2017

 

 

2017

 

2016

Net income (loss)

 

$

119,029

 

 

$

(769,166)

 

$

653,898

 

 

$

(496,856)

 

$

(6,018,014)

Depreciation, depletion and accretion expense

 

 

4,488,915

 

 

 

418,969

 

 

11,156,292

 

 

 

113,639

 

 

1,244,023

Interest expense

 

 

225,302

 

 

 

103,596

 

 

468,429

 

 

 

39,307

 

 

314,081

State income taxes

 

 

 —

 

 

 

4,212

 

 

 —

 

 

 

 —

 

 

13,401

EBITDA

 

 

4,833,246

 

 

 

(242,389)

 

 

12,278,619

 

 

 

(343,910)

 

 

(4,446,509)

Impairment of oil and natural gas properties

 

 

 —

 

 

 

306,959

 

 

 —

 

 

 

 —

 

 

4,992,897

Unit‑based compensation

 

 

434,197

 

 

 

151,265

 

 

569,889

 

 

 

50,422

 

 

453,795

Adjusted EBITDA

 

$

5,267,443

 

 

$

215,835

 

$

12,848,508

 

 

$

(293,488)

 

$

1,000,183

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash interest expense

 

 

166,707

 

 

 

219,900

 

 

276,246

 

 

 

34,505

 

 

280,010

Capital expenditures

 

 

 —

 

 

 

 —

 

 

 —

 

 

 

 —

 

 

 —

Cash available for distribution

 

$

5,100,736

 

 

$

(4,065)

 

$

 12,572,262

 

 

$

(327,993)

 

$

720,173

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

Partnership

 

 

Predecessor

 

 

Three Months Ended September 30, 

 

 

Three Months Ended September 30, 

 

Period from February 8, 2017 to September 30, 

 

 

Period from January 1, 2017 to February 7,

 

Nine Months Ended September 30, 

 

 

2017

 

 

2016

 

2017

 

 

2017

 

2016

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

5,387,438

 

 

$

406,518

 

$

13,965,478

 

 

$

186,719

 

$

956,793

Interest expense

 

 

225,302

 

 

 

103,596

 

 

468,429

 

 

 

39,307

 

 

314,081

State income taxes

 

 

 —

 

 

 

4,212

 

 

 —

 

 

 

 —

 

 

13,401

Impairment of oil and natural gas properties

 

 

 —

 

 

 

(306,959)

 

 

 —

 

 

 

 —

 

 

(4,992,897)

Amortization of loan origination costs

 

 

(15,625)

 

 

 

(12,723)

 

 

(41,667)

 

 

 

(4,241)

 

 

(34,245)

Amortization of tenant improvement allowance

 

 

 —

 

 

 

(32,603)

 

 

 —

 

 

 

2,864

 

 

25,777

Unit-based compensation

 

 

(434,197)

 

 

 

(151,265)

 

 

(569,889)

 

 

 

(50,422)

 

 

(453,795)

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL revenues receivable

 

 

555,908

 

 

 

1,258,156

 

 

496,886

 

 

 

(14,551)

 

 

(11,258)

Other receivables

 

 

65,175

 

 

 

(1,246,269)

 

 

258,785

 

 

 

(333,056)

 

 

(1,246,269)

Accounts payable

 

 

228,080

 

 

 

(274,023)

 

 

(152,569)

 

 

 

(247,972)

 

 

1,071,453

Other current liabilities

 

 

(1,178,835)

 

 

 

8,971

 

 

(2,146,834)

 

 

 

77,442

 

 

(89,550)

EBITDA

 

$

4,833,246

 

 

$

(242,389)

 

$

12,278,619

 

 

$

(343,910)

 

$

(4,446,509)

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Impairment of oil and natural gas properties

 

 

 —

 

 

 

306,959

 

 

 —

 

 

 

 —

 

 

4,992,897

Unit‑based compensation

 

 

434,197

 

 

 

151,265

 

 

569,889

 

 

 

50,422

 

 

453,795

Adjusted EBITDA

 

$

5,267,443

 

 

$

215,835

 

$

12,848,508

 

 

$

(293,488)

 

$

1,000,183

 

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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 financial condition and 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 all of the membership interests of our Predecessor were contributed 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 made 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 an asset acquisition. The fair value of the purchase price 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 as a whole and may not provide an accurate indication of what our actual results would have been if the transactions completed in connection with our IPO 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.

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 September 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 September 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

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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 September 30, 2017 of $240.8 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $78.4 million for the nine months ending September 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 three and nine months ended September 30, 2016, our Predecessor recorded non-cash impairment charges of approximately $0.3 million and $5.0 million, respectively, primarily due to changes in reserve values resulting from the decline 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 September 30, 2017, we had borrowed $22.2 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC (“Kimbell Operating”) and the acquisition of mineral and royalty interests for an aggregate purchase price of approximately $20.7 million. For the three months ended September 30, 2017 and the period from February 8, 2017 to September 30, 2017, we incurred $225,302 and $468,429, respectively, in interest expense.

In January 2014, our Predecessor entered into a credit agreement with Frost Bank, as lender. For the Predecessor 2017 Period and the three and nine months ended September 30, 2016, our Predecessor’s interest expense was $39,307, $103,596 and $314,081, respectively. Our Predecessor had outstanding borrowings of $10.6 million as of December 31, 2016. 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 Benny D. Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective services 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 services 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, 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 table below summarizes our and our Predecessor’s revenue and expenses and production data for the periods indicated (unaudited).

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

Partnership

 

 

Predecessor

 

 

Three Months Ended September 30,

 

 

Three Months Ended September 30,

 

Period from February 8, 2017 to September 30,

 

 

Period from January 1, 2017 to February 7,

 

Nine Months Ended September 30,

 

 

2017

  

  

2016

 

2017

  

  

2017

 

2016

Operating Results:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL revenues

 

$

8,351,399

 

 

$

969,084

 

$

20,656,741

 

 

$

318,310

 

$

2,572,477

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes

 

 

778,733

 

 

 

120,315

 

 

1,602,520

 

 

 

19,651

 

 

203,567

Depreciation, depletion and accretion expense

 

 

4,488,915

 

 

 

418,969

 

 

11,156,292

 

 

 

113,639

 

 

1,244,023

Impairment of oil and natural gas properties

 

 

 —

 

 

 

306,959

 

 

 —

 

 

 

 —

 

 

4,992,897

Marketing and other deductions

 

 

424,702

 

 

 

320,698

 

 

1,068,509

 

 

 

110,534

 

 

570,521

General and administrative expenses

 

 

2,314,718

 

 

 

463,501

 

 

5,707,093

 

 

 

532,035

 

 

1,252,001

Total costs and expenses

 

 

8,007,068

 

 

 

1,630,442

 

 

19,534,414

 

 

 

775,859

 

 

8,263,009

Operating income (loss)

 

 

344,331

 

 

 

(661,358)

 

 

1,122,327

 

 

 

(457,549)

 

 

(5,690,532)

Interest expense

 

 

225,302

 

 

 

103,596

 

 

468,429

 

 

 

39,307

 

 

314,081

Income (loss) before income taxes

 

 

119,029

 

 

 

(764,954)

 

 

653,898

 

 

 

(496,856)

 

 

(6,004,613)

State income taxes

 

 

 —

 

 

 

4,212

 

 

 —

 

 

 

 —

 

 

13,401

Net income (loss)

 

$

119,029

 

 

$

(769,166)

 

$

653,898

 

 

$

(496,856)

 

$

(6,018,014)

Production Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

 

108,692

 

 

 

13,752

 

 

267,966

 

 

 

3,696

 

 

41,548

Natural gas (Mcf)

 

 

888,694

 

 

 

93,794

 

 

2,205,292

 

 

 

32,961

 

 

343,078

Natural gas liquids (Bbls)

 

 

46,493

 

 

 

4,850

 

 

108,929

 

 

 

1,220

 

 

17,458

Combined volumes (Boe) (6:1)

 

 

303,301

 

 

 

34,234

 

 

744,444

 

 

 

10,410

 

 

116,186

 

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

The period presented for the three months ended September 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 September 30, 2017, our revenues were $8.4 million, an increase of $7.4 million, from $1.0 million for the three months ended September 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 and our Predecessor’s revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 303,301 Boe or 3,297 Boe/d, for the three months ended September 30, 2017, an increase of 269,067 Boe or 2,925 Boe/d, from 34,234 Boe or 372 Boe/d, for the three months ended September 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 September 30, 2017 with slightly higher production.

Our operators received an average of $43.95 per Bbl of oil, $2.79 per Mcf of natural gas and $19.75 per Bbl of NGL for the volumes sold during the three months ended September 30, 2017. Our Predecessor’s operators received an average of $42.08 per Bbl of oil, $3.11 per Mcf of natural gas and $20.37 per Bbl of NGL for the volumes sold during the three months ended September 30, 2016. The three months ended September 30, 2017 increased 4.4% or $1.87 per Bbl of oil and decreased 10.3% or $0.32 per Mcf of natural gas as compared to the three months ended September 30, 2016. The increase in the average price received for oil is consistent with increase in the price of oil experienced in the market, specifically when compared to the EIA average price increase of 7.4% or $3.33 per Bbl of oil. The change in the average price received for natural gas was attributable to the diversification of our natural gas producing interests when compared to the natural gas producing interests of our Predecessor.

Production and Ad Valorem Taxes

Our production and ad valorem taxes for the three months ended September 30, 2017 were $0.8 million, an increase of $0.7 million from $0.1 million in the three months ended September 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 September 30, 2017 was $4.5 million, an increase of $4.1 million from our Predecessor’s depreciation, depletion and accretion expense of $0.4 million for the three months ended September 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.

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. Our average depletion rate per barrel was $14.66 for the three months ended September 30, 2017, an increase of $4.87 per barrel from $9.79 average depletion rate per barrel for the three months ended September 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.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

No impairment expense was recorded for the three months ended September 30, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment of oil and natural gas properties for the Partnership in the current period. 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 $0.3 million for the three months ended September 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 include 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 September 30, 2017 were $0.4 million, an

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increase of $0.1 million from our Predecessor’s marketing and other deductions for the three months ended September 30, 2016 of $0.3 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 general and administrative expenses for the three months ended September 30, 2017 were $2.3 million, an increase of $1.8 million from our Predecessor’s general and administrative expenses of $0.5 million for the three months ended September 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 September 30, 2017 was $0.2 million as compared to our Predecessor’s interest expense of $0.1 million for the three months ended September 30, 2016.

Comparison of the Nine Months Ended September 30, 2017 to the Nine Months Ended September 30, 2016

The period presented for the nine months ended September 30, 2017 includes the results of operations of our Predecessor for the Predecessor 2017 Period and our results of operations for the period from February 8, 2017 to September 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 February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period, our and our Predecessor’s revenues were $20.7 and $0.3 million, respectively, for combined revenues of $21.0 million for the nine months ended September 30, 2017, an increase of $18.4 million, from $2.6 million for the nine months ended September 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 and our Predecessor’s revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 744,444 Boe or 3,168 Boe/d and 10,410 Boe or 274 Boe/d, for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period, respectively. The combined production for the nine months ended September 30, 2017 was 754,854 Boe or 2,765 Boe/d, an increase of 638,668 Boe or 2,341 Boe/d, from 116,186 Boe or 424 Boe/d, for the nine months ended September 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 September 30, 2017 with slightly higher production.

Our operators received an average of $45.14 per Bbl of oil, $2.77 per Mcf of natural gas and $20.85 per Bbl of NGL for the volumes sold during the period from February 8, 2017 to September 30, 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 NGL for the volumes sold during the Predecessor 2017 Period. For the combined nine months ended September 30, 2017, the operators received an average of $45.16 per Bbl of oil, $2.78 per Mcf of natural gas and $20.90 per Bbl of NGL for the volumes sold. Our Predecessor’s operators received an average of $38.11 per Bbl of oil, $2.14 per Mcf of natural gas and $14.56 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2016. Average prices received by the operators during the combined nine months ended September 30, 2017 increased 18.5% or $7.05 per Bbl of oil and 29.9% or $0.64 per Mcf of natural gas as compared to the nine months ended September 30, 2016. These increases are consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 19.2% or $7.95 per Bbl of oil and 28.6% or $0.67 per Mcf of natural gas for the comparable periods.

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Production and Ad Valorem Taxes

Our production and ad valorem taxes for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $1.6 million and $0.02 million, respectively. The combined production and ad valorem taxes for the nine months ended September 30, 2017 were $1.6 million, an increase of $1.4 million from $0.2 million in the nine months ended September 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 and our Predecessor’s depreciation, depletion and accretion expense for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period was $11.2 million and $0.1 million respectively for a combined expense of $11.3 million for the nine months ended September 30, 2017. This was an increase of $10.1 million from our Predecessor’s depreciation, depletion and accretion expense of $1.2 million for the nine months ended September 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.

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. Our and our Predecessor’s average depletion rate per barrel was $14.84 and $10.31 for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period, respectively. The combined average depletion rate per barrel for the nine months ended September 30, 2017 was $14.78, an increase of $4.07 per barrel from an average depletion rate of $10.71 per barrel for the nine months ended September 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.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

No impairment expense was recorded for the period from February 8, 2017 to September 30, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment of oil and natural gas properties for the Partnership for the period from February 8, 2017 to September 30, 2017. 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 $5.0 million for the nine months ended September 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 include product marketing expense, which is a post‑production expense, and our Predecessor’s marketing and other deductions also include lease operating expenses related to its non‑operated working interests. Marketing and other deductions for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $1.1 million and $0.1 million, respectively.  The combined marketing and other deductions for the nine months ended September 30, 2017 were $1.2 million, an increase of $0.6 million from our Predecessor’s marketing and other deductions for the nine months ended September 30, 2016 of $0.6 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 and our Predecessor’s general and administrative expenses for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $5.7 million and $0.5 million, respectively. General and administrative

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expenses for the combined nine months ended September 30, 2017 were $6.2 million, an increase of $4.9 million from our Predecessor’s general and administrative expenses of $1.3 million for the nine months ended September 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 and our Predecessor’s interest expense for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period was $0.5 million and $0.04 million, respectively. The interest expense for the combined nine months ended September 30, 2017 was $0.5 million as compared to our Predecessor’s interest expense of $0.3 million for the nine months ended September 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 (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 November 8, 2017, we had an outstanding balance of $29.6 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 General Partner’s Board of Directors (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

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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 NGL 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 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 Partnership’s calculated cash available for distribution was $0.28 per common unit for 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 was paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017.

On October 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended September 30, 2017. The distribution will be paid on November 13, 2017 to unitholders of record as of the close of business on November 6, 2017.

Cash Flows

The table below presents our cash flows and our Predecessor’s cash flows for the periods indicated (in thousands).

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

 

Period from February 8, 2017 to September 30, 

 

 

Period from January 1, 2017 to February 7,

 

Nine Months Ended September 30, 

 

 

 

2017

 

 

2017

 

2016

 

Cash Flow Data:

 

 

 

 

 

 

 

Cash flows provided by operating activities

 

$

13,965

 

 

$

187

 

$

957

 

Cash flows used in investing activities

 

 

(117,190)

 

 

 

(1)

 

 

(94)

 

Cash flows provided by (used in) financing activities

 

 

109,451

 

 

 

 —

 

 

(563)

 

Net increase in cash

 

$

6,226

 

 

$

186

 

$

300

 

 

Operating Activities

Our and our Predecessor’s operating cash flow is impacted by many variables, the most significant of which is the change in prices for oil, natural gas and NGL. 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 February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $14.0 million and $0.2 million, respectively. Cash flows provided by operating activities for the combined nine months ended September 30, 2017 were $14.2 million, an increase of $13.2 million compared to our Predecessor’s cash flows provided by operating activities of $1.0 million for the nine months ended September 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.

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Investing Activities

Cash flows used in investing activities for the period from February 8, 2017 to September 30, 2017 were $117.2 million, an increase of $117.1 million compared to our Predecessor’s cash flows used in investing activities for the nine months ended September 30, 2016 of $0.1 million. Our Predecessor’s cash flows used in investing activities were de minimis for the Predecessor 2017 Period. For the period from February 8, 2017 to September 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 $20.7 million to fund the acquisition of various mineral and royalty interests.

Financing Activities

Cash flows provided by financing activities was $109.5 million for the period from February 8, 2017 to September 30, 2017 as compared to our Predecessor’s cash used in financing activities of $0.6 million for the nine months ended September 30, 2016. Our Predecessor did not have any cash flows used in or provided by financing activities for the Predecessor 2017 Period. During the period from February 8, 2017 to September 30, 2017, we received $96.2 million in proceeds from our IPO, we borrowed $22.2 million, paid a distribution to unitholders of $8.7 million and paid loan origination costs of $0.3 million. During the nine months ended September 30, 2016, our Predecessor repaid $0.6 million on its long‑term debt.

Capital Expenditures

During the period from February 8, 2017 to September 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 $20.7 million for the acquisition of various mineral and royalty interests. During the Predecessor 2017 Period, 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 nine months ended September 30, 2016, our Predecessor spent $0.1 million on additional lease and well equipment and intangible drilling costs related to the Predecessor’s working interests and office equipment.

Indebtedness

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 November 8, 2017, we have borrowed $29.6 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC and the acquisition of various mineral and royalty interests for an aggregate purchase price of approximately $28.1 million.

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Predecessor Credit Facility

On January 31, 2014, our Predecessor entered into a credit agreement with Frost Bank for a $50.0 million credit facility. 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 under its credit facility was approximately $10.6 million, with an average interest rate of 3.39%. The credit facility 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 contribution of our Predecessor’s mineral and 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 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 and our Predecessor’s unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding these accounting policies.

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Inflation

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

Off‑Balance Sheet Arrangements

As of September 30, 2017, neither we, nor our Predecessor had any off‑balance sheet arrangements other than operating leases. As of September 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.

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 NGL 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 NGL 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 NGLs 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 September 30, 2017, we had total borrowings outstanding under our secured revolving credit facility of $22.2 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 September 30, 2017.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 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. There have been no material changes to the risk factors previously discussed in Item 1A—Risk Factors in the Partnership’s 2016 Form 10-K. 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 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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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)

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

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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: November 9, 2017

 

By:

/s/ Robert D. Ravnaas

 

 

 

Name:

Robert D. Ravnaas

 

 

 

Title:

Chief Executive Officer and Chairman

 

 

 

 

Principal Executive Officer

 

 

 

 

 

 

Date: November 9, 2017

    

By:

/s/ R. Davis Ravnaas

 

 

 

Name:

R. Davis Ravnaas

 

 

 

Title:

President and Chief Financial Officer

 

 

 

 

Principal Financial Officer

 

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