10-Q 1 krp-20180630x10q.htm 10-Q krp_Current_Folio_10Q

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10‑Q


 

 

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

 

For the quarterly period ended June 30, 2018

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 every Interactive Data File required to be submitted 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 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

 

Smaller reporting company

Emerging growth company

 

 

 

 

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

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

As of August 3, 2018, 26,839,462 common units of the registrant were outstanding.

 

 

 


 

KIMBELL ROYALTY PARTNERS, LP

FORM 10‑Q

TABLE OF CONTENTS

 

 

 

i


 

PART I – FINANCIAL INFORMATION

Item 1.  Condensed Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

June 30, 

 

December 31, 

 

 

2018

 

2017

ASSETS

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

Cash and cash equivalents

 

$

8,334,632

 

$

5,625,495

Oil, natural gas and NGL receivables

 

 

6,597,763

 

 

6,792,837

Accounts receivable and other current assets

 

 

226,641

 

 

236,673

Total current assets

 

 

15,159,036

 

 

12,655,005

Property and equipment, net

 

 

107,889

 

 

165,232

Oil and natural gas properties

 

 

 

 

 

 

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

 

 

287,050,787

 

 

297,609,797

Less: accumulated depreciation, depletion, accretion and impairment

 

 

(77,946,337)

 

 

(15,394,238)

Total oil and natural gas properties

 

 

209,104,450

 

 

282,215,559

Deposits on oil and natural gas properties

 

 

23,533,243

 

 

 —

Other assets

 

 

1,189,994

 

 

 —

Loan origination costs, net

 

 

223,958

 

 

255,208

Total assets

 

$

249,318,570

 

$

295,291,004

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS' CAPITAL

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

Accounts payable

 

$

5,239,072

 

$

316,486

Other current liabilities

 

 

1,226,727

 

 

1,746,662

Commodity derivative liabilities

 

 

400,798

 

 

183,957

Total current liabilities

 

 

6,866,597

 

 

2,247,105

Commodity derivative liabilities

 

 

599,561

 

 

134,872

Long-term debt

 

 

42,972,997

 

 

30,843,593

Total liabilities

 

 

50,439,155

 

 

33,225,570

Commitments and contingencies

 

 

 

 

 

 

Partners' capital

 

 

198,879,415

 

 

262,065,434

Total liabilities and partners' capital

 

$

249,318,570

 

$

295,291,004

 

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

1


 

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Three Months Ended June 30, 

 

Three Months Ended June 30, 

 

Six Months Ended June 30, 

 

Period from

February 8, 2017 to June 30, 

 

 

Period from
January 1, 2017 to February 7,

 

 

2018

 

2017

 

2018

 

2017

 

 

2017

Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL revenues

 

$

11,246,287

 

$

7,751,998

 

$

22,422,590

 

$

12,305,342

 

 

$

318,310

Loss on commodity derivative instruments

 

 

(538,389)

 

 

 —

 

 

(823,354)

 

 

 —

 

 

 

 —

Total revenues

 

 

10,707,898

 

 

7,751,998

 

 

21,599,236

 

 

12,305,342

 

 

 

318,310

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes

 

 

805,396

 

 

617,681

 

 

1,621,397

 

 

823,787

 

 

 

19,651

Depreciation, depletion and accretion expense

 

 

3,431,594

 

 

4,131,717

 

 

7,887,302

 

 

6,667,377

 

 

 

113,639

Impairment of oil and natural gas properties

 

 

 —

 

 

 —

 

 

54,753,444

 

 

 —

 

 

 

 —

Marketing and other deductions

 

 

609,033

 

 

386,681

 

 

1,178,875

 

 

643,807

 

 

 

110,534

General and administrative expense

 

 

4,000,022

 

 

2,181,293

 

 

6,770,794

 

 

3,392,375

 

 

 

532,035

Total costs and expenses

 

 

8,846,045

 

 

7,317,372

 

 

72,211,812

 

 

11,527,346

 

 

 

775,859

Operating income (loss)

 

 

1,861,853

 

 

434,626

 

 

(50,612,576)

 

 

777,996

 

 

 

(457,549)

Other expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

483,558

 

 

182,975

 

 

833,600

 

 

243,127

 

 

 

39,307

Net income (loss)

 

$

1,378,295

 

$

251,651

 

 

(51,446,176)

 

 

534,869

 

 

$

(496,856)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.08

 

$

0.02

 

$

(3.14)

 

$

0.03

 

 

$

(0.82)

Diluted

 

$

0.08

 

$

0.02

 

$

(3.14)

 

$

0.03

 

 

$

(0.82)

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

16,377,476

 

 

16,332,708

 

 

16,361,619

 

 

16,332,708

 

 

 

604,137

Diluted

 

 

16,809,149

 

 

16,422,446

 

 

16,361,619

 

 

16,389,814

 

 

 

604,137

 

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

2


 

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(Unaudited)

 

 

 

 

 

 

 

 

 

   

Units

   

Total

Partners' capital - December 31, 2017

 

 

16,509,799

 

$

262,065,434

 

 

 

 

 

 

 

Distributions to unitholders

 

 

 —

 

 

(13,131,816)

 

 

 

 

 

 

 

Restricted units granted, net of forfeitures

 

 

329,663

 

 

 —

 

 

 

 

 

 

 

Unit-based compensation

 

 

 —

 

 

1,391,973

 

 

 

 

 

 

 

Net loss

 

 

 —

 

 

(51,446,176)

 

 

 

 

 

 

 

Partners' capital - June 30, 2018

 

 

16,839,462

 

$

198,879,415

 

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

 

 

3


 

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

  

 

Predecessor

 

 

Six Months Ended June 30, 

 

Period from
February 8, 2017 to June 30, 

  

 

Period from

January 1, 2017 to

February 7,

 

   

2018

 

2017

  

 

2017

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

  

 

 

 

Net income (loss)

 

$

(51,446,176)

 

$

534,869

  

  

$

(496,856)

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

 

 

 

 

 

 

  

  

 

 

Depreciation, depletion and accretion expense

 

 

7,887,302

 

 

6,667,377

  

  

 

113,639

Impairment of oil and natural gas properties

 

 

54,753,444

 

 

 —

  

  

 

 —

Amortization of loan origination costs

 

 

31,250

 

 

26,042

  

  

 

4,241

Amortization of tenant improvement allowance

 

 

 —

 

 

 —

  

  

 

(2,864)

Unit-based compensation

 

 

1,391,973

 

 

135,692

  

  

 

50,422

Loss on commodity derivative instruments

 

 

681,530

 

 

 —

 

 

 

 —

Changes in operating assets and liabilities:

 

 

 

 

 

 

  

  

 

 

Oil, natural gas and NGL receivables

 

 

195,074

 

 

59,022

  

  

 

14,551

Accounts receivable and other current assets

 

 

10,032

 

 

(193,610)

  

  

 

333,056

Accounts payable

 

 

1,204,349

 

 

380,649

  

  

 

247,972

Other current liabilities

 

 

(519,935)

 

 

967,999

  

  

 

(77,442)

Net cash provided by operating activities

 

 

14,188,843

 

 

8,578,040

  

  

 

186,719

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

  

  

 

 

Purchases of property and equipment

 

 

(31,304)

 

 

(21,214)

  

  

 

 —

Proceeds from sale of oil and natural gas properties

 

 

10,576,595

 

 

 —

  

  

 

 —

Deposits on oil and natural gas properties

 

 

(21,005,000)

 

 

 —

  

  

 

 —

Purchase of oil and natural gas properties

 

 

(17,585)

 

 

(113,180,523)

  

  

 

(523)

Net cash used in investing activities

 

 

(10,477,294)

 

 

(113,201,737)

  

  

 

(523)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

  

  

 

 

Proceeds from initial public offering

 

 

 —

 

 

96,255,000

  

  

 

 —

Distributions to unitholders / members

 

 

(13,131,816)

 

 

(3,756,523)

  

  

 

 —

Borrowings on long-term debt

 

 

19,000,000

 

 

18,265,090

  

  

 

 —

Repayments on long-term debt

 

 

(6,870,596)

 

 

 —

  

  

 

 —

Payment of loan origination costs

 

 

 —

 

 

(312,500)

  

  

 

 —

Net cash provided by (used in) financing activities

 

 

(1,002,412)

 

 

110,451,067

  

  

 

 —

NET INCREASE IN CASH AND CASH EQUIVALENTS

 

 

2,709,137

 

 

5,827,370

  

  

 

186,196

CASH AND CASH EQUIVALENTS, beginning of period

 

 

5,625,495

 

 

 —

  

  

 

505,880

CASH AND CASH EQUIVALENTS, end of period

 

$

8,334,632

 

$

5,827,370

  

  

$

692,076

Supplemental cash flow information:

 

 

 

 

 

 

  

  

 

 

Cash paid for interest

 

$

977,487

 

$

109,539

  

  

$

34,505

Cash paid for taxes

 

$

 —

 

$

 —

  

  

$

5,355

Non-cash investing and financing activities:

 

 

 

 

 

 

  

  

 

 

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

 

$

3,718,237

 

$

16,568

  

  

$

 —

Capital expenditures through issuance of common units

 

$

 —

 

$

176,404,698

  

  

$

 —

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

 

 

4


 

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED 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 AND BASIS OF PRESENTATION

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 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 was 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 included 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.

Basis of Presentation

The accompanying unaudited interim condensed 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 United States (“U.S.”) Securities and Exchange Commission (“SEC”). As a result, the accompanying unaudited interim condensed consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim condensed 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, 2017 and 2016, which are included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017. In the opinion of the Partnership’s management, the unaudited interim condensed 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.

Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes.  Actual results could differ from those estimates.

5


 

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED 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.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in Partnership’s 2017 Form 10-K as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the six months ended June 30, 2018.

Recently Issued Accounting Pronouncements

In June 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-07, Improvements to Nonemployee Share-Based Payment Accounting. ASU 2018-07 simplifies the accounting for share-based payments to nonemployees by aligning it with the accounting for share-based payments to employees, with certain exceptions. The amendments in this ASU are effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year, with early adoption permitted. The Partnership early adopted ASU 2018-07 effective January 1, 2018.  This standard substantially aligned the accounting for share based payments to employees and nonemployees.  The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations—Clarifying the Definition of a Business.” This update applies 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. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations.

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 and is still assessing the impact it will have on our financial statements.

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

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Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

On January 1, 2018 the Partnership adopted ASU 2014-09 using the full retrospective method. The Partnership completed its review of a representative sample of revenue contracts covering its material revenue streams and determined that there is no impact to its consolidated financial statements, results of operations or liquidity. When comparing the Partnership’s historical revenue recognition to the newly applied revenue recognition under ASC 606, there was no change to the amount or timing of revenue recognized. Therefore, no quantitative adjustment was required to be made to the prior periods presented in the unaudited condensed consolidated financial statements after the adoption of ASC 606. Upon adoption the Partnership had not altered its existing information technology and internal controls outside of the contract review processes in order to identify impacts of future revenue contracts the Partnership may enter into.

Accounting Policy – Revenues from royalty properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received one to four months after the production month, the Partnership accrues for revenue earned but not received by estimating production volumes and product prices.

Revenues from lease bonus are recorded upon receipt. The lease bonus is separate from the lease itself and is recognized as revenue to the Partnership upon receipt of payment.

 

NOTE 3—DERIVATIVES

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable–to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. 

At June 30, 2018, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.

 

 

 

 

 

 

 

 

 

Three Months Ended June 30, 

 

Six Months Ended June 30, 

 

 

2018

 

2018

Beginning fair value of commodity derivative instruments

 

$

(531,287)

 

$

(318,829)

Loss on commodity derivative instruments

 

 

(538,389)

 

 

(823,354)

Net cash paid on settlements of derivative instruments

 

 

69,317

 

 

141,824

Ending fair value of commodity derivative instruments

 

$

(1,000,359)

 

$

(1,000,359)

At June 30, 2018, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

 

 

 

 

 

 

 

 

Notional

 

Weighted Average

 

 

Volumes (MBbls)

 

Fixed Price (per Bbl)

July 2018 - December 2018

 

25,252

 

$

56.00

January 2019 - December 2019

 

43,070

 

$

53.07

January 2020 - March 2020

 

11,011

 

$

56.03

April 2020 - June 2020

 

12,194

 

$

61.43

 

 

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Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Natural Gas Price Swaps

 

 

 

 

 

 

 

 

Notional

 

Weighted Average

 

 

Volumes (MMBtu)

 

Fixed Price (per MMBtu)

July 2018 - December 2018

 

177,744

 

$

2.71

January 2019 - December 2019

 

352,590

 

$

2.76

January 2020 - March 2020

 

96,915

 

$

2.94

April 2020 - June 2020

 

109,473

 

$

2.52

 

 

NOTE 4—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, oil, natural gas and NGL receivables, accounts receivable and other current assets, accounts payable and other current liabilities included in the unaudited condensed consolidated balance sheets approximated fair value at June 30, 2018 and December 31, 2017. As a result, these financial assets and liabilities are not discussed below.

·

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

·

Level 2—Quoted prices for similar assets or liabilities in non-active markets, or inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

·

Level 3—Measurement based on prices or valuations models that require inputs that are both unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and six months ended June 30, 2018 and 2017.

 

The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets.

NOTE 5—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consists of the following:

 

 

 

 

 

 

 

 

    

June 30, 

 

December 31, 

 

 

2018

 

2017

Oil and natural gas properties

 

 

 

 

 

 

Proved properties

 

$

287,050,787

 

$

297,609,797

Less: accumulated depreciation, depletion and impairment

 

 

(77,946,337)

 

 

(15,394,238)

Net oil and natural gas properties

 

$

209,104,450

 

$

282,215,559

No impairment expense was recorded for the three months ended June 30, 2018.  The Partnership recorded an impairment on its oil and natural gas properties of $54.8 million during the six months ended June 30, 2018, as a result of our quarterly full cost ceiling analysis during the three months ended March 31, 2018. No impairment expense was recorded for the period from February 8, 2017 to June 30, 2017 or for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”).

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NOTE 6—ACQUISITIONS AND DIVESTITURES

2018 Activity

In the month of May 2018, the Partnership executed two purchase and sale agreements to sell a small portion of its Delaware Basin acreage for $10.6 million. At the time of the divestiture, the sales represented approximately 29 Boe per day of production, less than 0.8% of total production and 59 net royalty acres, approximately 0.08% of total net royalty acres.

On May 28, 2018, the Partnership entered into securities purchase agreements to acquire all of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Resources, LP (the “Haymaker Acquisition”) for an aggregate purchase price of $451.7 million.  The Haymaker Acquisition closed on July 12, 2018.  In connection with the execution of the securities purchase agreements, the Partnership paid a $21.0 million deposit on the cash portion of the total purchase price.  This deposit is included in deposits on oil and natural gas properties on the accompanying condensed consolidated balance sheet.  See Note 14 – Subsequent Events for details on the closing of the Haymaker Acquisition.

2017 Activity

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

During the period from July 1, 2017 through December 31, 2017, the Partnership acquired mineral and royalty interests underlying over 88,000 gross acres, and over 3,800 net royalty acres, for an aggregate purchase price of approximately $12.5 million. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.

NOTE 7—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. In connection with the Haymaker Acquisition, the Partnership amended its secured revolving credit facility.  Availability under the secured revolving credit facility will continue to equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will continue to 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 its wholly owned subsidiaries. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Pursuant to the amendment, aggregate commitments remain at $200.0 million providing for maximum availability under the revolving credit facility of $200.0 million with the first redetermination date to be February 1, 2019. The amendment to the secured revolving credit facility permits aggregate commitments to be increased to $500.0 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. During the six months ended June 30, 2018, the Partnership borrowed an additional $19.0 million under the secured revolving credit facility and repaid $6.9 million of

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the total outstanding borrowings.  As of June 30, 2018, the Partnership’s outstanding balance was $43.0 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of June 30, 2018.  See Note 14 – Subsequent Events for details on the amendment to the existing credit agreement.

At June 30, 2018, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% or Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the six months ended June 30, 2018, the weighted average interest rate on the Partnership’s outstanding borrowings was 4.47%.

 

NOTE 8—COMMON UNITS

2018 Activity

On January 26, 2018, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.36 per common unit for the quarter ended December 31, 2017. The distribution was paid on February 14, 2018 to unitholders of record as of the close of business on February 7, 2018.

On January 26, 2018, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee (the “Conflicts and Compensation Committee”) of the Board of Directors, approved the grant of a total of 326,654 restricted units to certain employees, directors and consultants under the Long-Term Incentive Plan (“LTIP”).  Such grants were made on January 29, 2018.

On April 27, 2018 the Board of Directors declared a quarterly cash distribution of $0.42 per common unit for the quarter ended March 31, 2018. The distribution was paid on May 14, 2018 to unitholders of record as of the close of business on May 7, 2018.

On May 9, 2018, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of a total of 4,478 of restricted units to a new director under the LTIP.  This grant was made on May 9, 2018.

As of June 30, 2018, 16,839,462 common units of the Partnership were outstanding.  In connection with the Haymaker Acquisition, which closed on July 12, 2018, the Partnership issued 10,000,000 common units and 110,000 Series A Cumulative Convertible Preferred Units (the “Series A Preferred Units”) representing limited partner interests in the Partnership as described in Note 14 – Subsequent Events.

On July 27, 2018 the Board of Directors declared a quarterly cash distribution of $0.43 per common unit for the quarter ended June 30, 2018. The distribution will be paid on August 13, 2018 to unitholders of record as of the close of business on August 6, 2018The number of common units outstanding as of the record date for the second quarter distribution included 10,000,000 common units issued as partial consideration in the Haymaker Acquisition.  Under the terms of the securities purchase agreements for the Haymaker Acquisition, the Partnership is entitled to net revenues for production from the acquired properties on and after the effective date of April 1, 2018.  The Partnership will pay a portion of these net revenues (approximately $4.3 million) in the second quarter 2018 distribution.  Net revenues for production from the acquired properties will be recorded on the Partnership’s consolidated statement of operations for periods on and after July 12, 2018, the closing date of the transaction. 

2017 Activity

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 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 distribution was paid on May 15, 2017 to unitholders of record as of the close of

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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 May 12, 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 a total of 163,324 restricted units to certain employees, directors and consultants under the LTIP.  Such grants were made on May 12, 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 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 each 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.

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 was paid on November 13, 2017 to unitholders of record as of the close of business on November 6, 2017.

NOTE 9—EARNINGS (LOSS) PER UNIT

Basic earnings (loss) 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 10—Unit-Based Compensation. The calculation of diluted net loss per share for the six months ended June 30, 2018 excludes 438,785 of non-vested shares of restricted stock units issuable upon vesting, because their inclusion in the calculation would be anti-dilutive. For the Predecessor 2017 Period, 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 accompanying unaudited condensed consolidated statement of operations for this period.

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Three Months Ended June 30, 

 

Three Months Ended June 30, 

 

Six Months Ended June 30, 

 

Period from

February 8, 2017 to June 30, 

 

 

Period from

January 1, 2017 to February 7,

 

 

2018

 

2017

 

2018

 

2017

 

 

2017

Net income (loss)

 

$

1,378,295

 

$

251,651

 

$

(51,446,176)

 

$

534,869

 

 

$

(496,856)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

           0.08

 

$

0.02

 

$

            (3.14)

 

$

0.03

 

 

$

(0.82)

Diluted

 

$

           0.08

 

$

0.02

 

$

            (3.14)

 

$

0.03

 

 

$

(0.82)

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

16,377,476

 

 

16,332,708

 

 

16,361,619

 

 

16,332,708

 

 

 

604,137

Diluted

 

 

16,809,149

 

 

16,422,446

 

 

16,361,619

 

 

16,389,814

 

 

 

604,137

 

 

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NOTE 10—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. After the adoption of ASU 2018-07, compensation expense for consultants will be treated in the same manner as that of the employees and directors.

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, directors and consultants is determined by utilizing the market value of our common units on the respective grant date.  The following table presents a summary of the Partnership’s unvested common units.

 

 

 

 

 

 

 

 

 

    

 

    

Weighted

    

Weighted

 

 

 

 

Average

 

Average

 

 

 

 

Grant-Date

 

Remaining

 

 

 

 

Fair Value

 

Contractual

 

 

Units

 

per Unit

 

Term

Unvested at December 31, 2017

 

167,571

 

$

18.655

 

1.364 years

Granted - service condition employees

 

327,306

 

 

19.080

 

 -

Granted - service condition consultants

 

3,826

 

 

16.260

 

 -

Forfeited

 

(1,469)

 

 

(16.260)

 

 -

Vested

 

(58,449)

 

 

(18.470)

 

 -

Unvested at June 30, 2018

 

438,785

 

$

18.871

 

1.529 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.  For the Predecessor 2017 Period, total compensation expense for awards under the Predecessor’s long-term incentive plan was $0.05 million and is included general and administrative expenses in the accompanying unaudited condensed consolidated statement 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 11—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 June 30, 2018, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $32,500, $131,714, $30,000, $89,209 and $130,495, respectively. During the six months ended June 30, 2018, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $65,000, $263,428, $60,000, $178,419 and $260,991, respectively.

During the Predecessor 2017 Period, the Predecessor had certain related party receivables and payables; however, such amounts were de minimis.

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NOTE 12—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 11―Related Party Transactions.

NOTE 13—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership has situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage.  The Partnership is currently assessing such a situation relating to certain non-producing acreage in its portfolio, the resolution of which is not expected to have a material impact on the Partnership’s condensed consolidated financial statements, and no amounts have been accrued as of June 30, 2018.

NOTE 14—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to June 30, 2018 in the preparation of its condensed consolidated financial statements.

Haymaker Acquisition

 

On July 12, 2018, the Partnership completed the Haymaker Acquisition in a transaction valued at approximately $451.7 million. The purchase price for the Haymaker Acquisition was comprised of (i) cash consideration of approximately $216.8 million, which was reduced by approximately $6.4 million of cash acquired and increased by approximately $5.9 million in capitalized transaction costs for a net amount of approximately $216.3 million (the “Cash Consideration”) and (ii) 10,000,000 common units of the Partnership, valued at approximately $235.4 million based on the closing price of $23.45 on July 12, 2018 (the “Common Unit Consideration”)The Partnership funded the Cash Consideration with borrowings under the Amended Credit Agreement (as defined below) and net proceeds from the Preferred Unit Transaction (as defined below).  The Common Unit Consideration was issued in a private placement exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"), in reliance on the exemptions set forth in Section 4(a)(2) of the Securities Act.  The assets acquired in the Haymaker Acquisition, consist of approximately 5.4 million gross acres and 43,000 net royalty acres.

  

Voting Agreements

 

On July 12, 2018, pursuant to the Haymaker Acquisition, the Partnership entered into (i) a Voting Agreement with Haymaker Minerals and Royalties, LLC (“Haymaker Minerals”) and (ii) a Voting Agreement with EIGF Aggregator III LLC, TE Drilling Aggregator LLC and Haymaker Management, LLC (collectively, the “Haymaker Resources Holders” and the “Voting Agreements”), pursuant to which Haymaker Minerals and the Haymaker Resources Holders have agreed to vote in favor of (A) the Partnership’s proposal to change its U.S. federal income tax status from a partnership to an entity taxable as a corporation and (B) an amendment to the Partnership’s LTIP to increase the number of common units eligible for issuance thereunder, subject to a cap set forth in the Haymaker Acquisition.

 

The Voting Agreements prohibit Haymaker Minerals and the Haymaker Resources Holders from selling or disposing of common units at any time during the term of the Voting Agreements, subject to certain exceptions. The Voting Agreements terminate on January 8, 2019.

  

Registration Rights Agreement

 

On July 12, 2018, pursuant to the terms of the Haymaker Acquisition and the Preferred Purchase Agreement (as defined below), the Partnership entered into a registration rights agreement (the “Registration Rights Agreement”) with Haymaker Minerals, the Haymaker Resources Holders and the Purchasers (as defined below), pursuant to which, among other things, the Partnership has agreed to (i) prepare, file with the SEC and use its reasonable best efforts to cause to

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become effective within 160 days of the execution of the Registration Rights Agreement, a shelf registration statement (the “Shelf Registration Statement”) with respect to the resale of the common units issued to Haymaker Minerals and the Haymaker Resources Holders and issuable upon conversion of the Series A Preferred Units by the Purchasers (all such common units being “Registrable Securities”) that would permit some or all of the Registrable Securities to be resold in registered transactions, (ii) use its reasonable best efforts to maintain the effectiveness of the Shelf Registration Statement while Haymaker Minerals, the Haymaker Resources Holders, the Purchasers and each of their transferees that hold Registrable Securities are in possession of Registrable Securities and (iii) under certain circumstances, initiate underwritten offerings for the Registrable Securities.

 

If the Shelf Registration Statement is not effective prior to the 180th day after the execution of the Registration Rights Agreement and, likewise, if a Shelf Registration Statement is not effective prior to the day the Series A Preferred Units are convertible into common units pursuant to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Second Amended and Restated Partnership Agreement”), then Haymaker Minerals, the Haymaker Resources Holders and the Purchasers, as applicable, will be entitled to certain liquidated damages as set forth in the Registration Rights Agreement.

 

In addition, the Registration Rights Agreement permits Haymaker Minerals, the Haymaker Resources Holders and the Purchasers to request to sell any or all of their Registrable Securities in an underwritten offering that is registered pursuant to a Shelf Registration Statement, subject to certain exceptions, including, among other things, that the gross proceeds from the sale are reasonably expected to exceed $50 million in the aggregate.

 

On July 30, 2018, the Partnership filed a registration statement on Form S-3 (the “Form S-3”) to satisfy, in part, certain rights and obligations under the Registration Rights Agreement. The Form S-3 registers (i) the offer and sale by the Partnership of up to an aggregate of $200,000,000 of its securities and (ii) the offer and resale of up to an aggregate of 15,945,946 of the Partnership’s common units by the holders of Registrable Securities named therein.  As of the date of filing of this report, the Form S-3 had not yet been declared effective by the SEC.

Transition Services Agreement

 

On July 12, 2018, pursuant to the Haymaker Acquisition, the Partnership entered into a Transition Services Agreement with Haymaker Services, LLC (“Haymaker Services” and the “Transition Services Agreement”). Pursuant to the Transition Services Agreement, Haymaker Services will provide certain administrative services and accounting assistance on a transitional basis for total compensation of approximately $2.3 million through December 31, 2018, at which point, the Transition Services Agreement will terminate.

 

Amendment to the Existing Credit Agreement

 

On July 12, 2018, in connection with the Haymaker Acquisition, the Partnership entered into an amendment (the “Credit Agreement Amendment”) to the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (the “Existing Credit Agreement” and, the Existing Credit Agreement as amended by the Credit Agreement Amendment, the “Amended Credit Agreement”), by and among the Partnership, certain subsidiaries of the Partnership as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto. The Credit Agreement Amendment increased commitments under the Amended Credit Agreement from $50 million to $200 million. Under the Amended Credit Agreement, availability under the facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The initial borrowing base under the Amended Credit Agreement was set at $200 million. The Amended Credit Agreement permits aggregate commitments under the facility to be increased to $500 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.

 

The Credit Agreement Amendment amends the Existing Credit Agreement to provide for, among other things, (i) the addition of the subsidiaries the Partnership acquired in the Haymaker Acquisition, as well as Kimbell Royalty Operating, LLC (“OpCo”), as guarantors under the Amended Credit Agreement, (ii) limitations on the Partnership’s ability to incur certain debt or issue preferred equity (other than 110,000 Series A Preferred Units representing limited partner interests in the Partnership, (iii) limitations on redemptions of the Series A Preferred Units and the ability of the Partnership

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and the restricted subsidiaries of the Partnership to make distributions and other restricted payments, in each case, unless certain conditions are satisfied, (iv) increased limitations on the Partnership’s ability to dispose of certain assets or encumber certain assets, (v) a decrease in the applicable margin under the Existing Credit Agreement, which varies based upon the level of borrowing base usage, by 0.25% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 2.00% to 3.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement) and (vi) the addition of certain restrictions on the Partnership’s and OpCo’s ability to take certain actions or amend their organizational documents.  Additionally, the Credit Agreement Amendment permits certain transactions to effect the intended change of the Partnership’s U.S. federal income tax status from a pass-through partnership to an entity taxable as a corporation by means of a “check-the-box” election and to effect an “up-C” structure, including allowing for all assets and liabilities of the Partnership to be transferred to OpCo and for OpCo to become a non-wholly owned subsidiary guarantor.

 

Preferred Purchase Agreement

 

On May 28, 2018, the Partnership entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Purchase Agreement”) with certain affiliates of Apollo Capital Management, L.P. (collectively, the “Purchasers”) to issue and sell the Series A Preferred Units.  The Series A Preferred Units were offered in a private placement (the “Preferred Unit Transaction”) exempt from the registration requirements of the Securities Act in reliance on the exemptions set forth in Section 4(a)(2) of the Securities Act.  The Preferred Unit Transaction closed on July 12, 2018, with the Series A Preferred Units being issued and sold for a cash purchase price of $1,000 per Series A Preferred Unit, resulting in gross proceeds to the Partnership of $110 million.

 

The Series A Preferred Units pay a 7% distribution rate and are convertible by the Purchasers after two years at a 30% discount to the issue price, subject to certain conditions.  The Partnership may redeem the Series A Preferred Units at any time at a redemption price that is the greater of 1.2 times the invested capital.

 

Board Rights Agreement

 

On July 12, 2018, pursuant to the Preferred Purchase Agreement, the Partnership, the General Partner, and Kimbell GP Holdings, LLC entered into a Board Representation and Observation Agreement (the “Board Rights Agreement”) with the Purchasers. Pursuant to the Board Rights Agreement, the Partnership granted holders of the Series A Preferred Units board observer rights beginning three years after the closing of the Preferred Unit Transaction, and board appointment rights beginning four years after the closing of the Preferred Unit Transaction and in the case of events of default with respect to the Series A Preferred Units.

 

Recapitalization Agreement

 

 On July 24, 2018, the Partnership entered into a Recapitalization Agreement (the "Recapitalization Agreement"), by and among Haymaker Minerals and Haymaker Resources Holders, Haymaker Resources, LP, the Kimbell Art Foundation (the "Foundation"), the Partnership, the General Partner, and Kimbell Royalty Operating, LLC, a wholly owned subsidiary of the Partnership (the "Operating Company"), pursuant to which (a) the Partnership's equity interest in the Operating Company will be recapitalized into 13,886,204 newly issued common units of the Operating Company ("OpCo Common Units") and 110,000 newly issued Series A Preferred Units of the Operating Company ("OpCo Series A Preferred Units") and (b) the 10,000,000 and 2,953,258 common units held by the Haymaker Holders and the Foundation, respectively, will be exchanged for (i) 10,000,000 and 2,953,258 newly issued Class B common units representing limited partner interests of the Partnership ("Class B Units"), respectively, and (ii) 10,000,000 and 2,953,258 newly issued OpCo Common Units, respectively, in connection with the implementation of an Up-C structure (the "Restructuring"). The Class B Units and OpCo Common Units will be exchangeable together into an equal number of Common Units.

 

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Derivative Transactions

 

On July 12, 2018, the Partnership entered into additional oil and natural gas commodity derivative agreements with Frost Bank for the years ending December 31, 2018, 2019 and through the six months ending June 30, 2020.  The commodity derivative contracts consist of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.  The Partnership hedges its daily production based on the amount of debt and/or preferred equity as a percent of its enterprise value.  Prior to the Haymaker Acquisition, this amount constituted approximately 10% of daily oil and natural gas production.  Following the closing of the Haymaker Acquisition, the Partnership hedged daily oil and natural gas production of approximately 30% of our post-acquisition production.  The additional oil and natural gas commodity derivative agreements represent the Partnership’s mitigation of the inherent commodity price risk associated with the oil and natural gas production from the properties acquired in the Haymaker Acquisition. 

Tax Election and Restructuring

In preparation for the Restructuring (as defined below), the Partnership formed and contributed all of its assets and liabilities to Kimbell Royalty Operating, LLC, the Partnership’s wholly owned subsidiary (the “Operating Company”).  Further, on July 24, 2018, the Partnership entered into a Recapitalization Agreement, dated as of July 24, 2018, by and among Haymaker Minerals & Royalties, LLC, Haymaker Management, LLC and certain affiliates of Haymaker Resources, LP (each of the preceding entities, the “Haymaker Holders”), Haymaker Resources, LP, the Kimbell Art Foundation, the Partnership, our general partner and the Operating Company, pursuant to which (i) the Partnership’s equity interest in the Operating Company will be recapitalized into 13,886,204 newly issued common units of the Operating Company (“OpCo Common Units”) and 110,000 newly issued Series A Cumulative Convertible Preferred Units of the Operating Company (“OpCo Series A Preferred Units”), (ii) the Haymaker Holders and the Kimbell Art Foundation will deliver and assign to the Partnership the 10,000,000 and 2,953,258 common units they own, respectively, in exchange for (a) 10,000,000 and 2,953,258 newly issued Class B common units representing limited partner interests in the Partnership (the “Class B Units”), respectively, and (b) 10,000,000 and 2,953,258 newly issued OpCo Common Units, respectively, and (iii) the Partnership will amend and restate the limited liability company agreement of the Operating Company (the “Operating Company Agreement”) to reflect these transactions (collectively, the “Restructuring”). At the consummation of the Restructuring, the Partnership will enter into an exchange agreement with the Haymaker Holders, the Kimbell Art Foundation, the Partnership’s general partner and the Operating Company granting the Haymaker Holders and the Kimbell Art Foundation the right to exchange their OpCo Common Units and Class B Units for common units.

On July 26, 2018, the Partnership filed a preliminary information statement on Schedule 14C with the SEC (the “Information Statement”) related to the amendment and restatement of the partnership agreement in connection with the Partnership’s decision to change its United States federal income tax status from a pass-through “partnership” to an entity taxable as a “corporation” by means of a “check-the-box” election (the “Tax Election,” and, together with the Restructuring and related transactions described in the Information Statement, the “Up-C Transaction”) and an amendment to its LTIP.  Pursuant to Rule 14c-2 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the written consent will become effective on or after the date that is 20 calendar days following the date that the definitive information statement on Schedule 14C is first sent or given to the Partnership’s unitholders.

 

 

 

16


 

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 condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10‑Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017.

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.

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 Royalties, LLC (“the Predecessor,” or “Rivercrest”), the Predecessor for accounting and financial reporting 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:

·

the outcome of any legal proceedings that may be instituted against us or others relating to the actions described in the preliminary information statement on Schedule 14C we filed with the U.S. Securities and Exchange Commission (“SEC”) on July 26, 2018 (the “Information Statement”), or the transactions contemplated thereby;

·

the effect of the announcement of the Tax Election (as defined below) or the Restructuring (as defined below) on our customer relationships, operating results and business generally;

·

the risks that the Tax Election disrupts current plans and operations;

·

the amount of the costs, fees, expenses and charges related to the Tax Election and the Restructuring;

·

the failure to satisfy the conditions required to obtain the unitholder approval described in the Information Statement;

·

the failure to realize the anticipated benefits of the Haymaker Acquisition (as defined below), the Preferred Units Transaction (as defined below), the Tax Election or the Restructuring;

·

our ability to execute our business strategies;

·

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

17


 

·

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;

·

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, tax laws 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

We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States of America (“United States” or “U.S.”). 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 NGLs from the acreage underlying our interests, net of post‑production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of June 30, 2018, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 2.0 million gross acres, with approximately 35% of our aggregate acres located in the Permian Basin. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of June 30, 2018, over 98% 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

18


 

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 30,000 wells in the Permian Basin.

Recent Developments

Commodity Derivative Instruments

On June 29, 2018, we entered into additional oil and natural gas fixed price swaps with Frost Bank for the second quarter of 2020. The fixed price swaps consist of 12,194 Bbl of oil at a fixed rate of $61.43 per Bbl and 109,473 MMBtu of natural gas at a fixed rate of $2.52 per MMBtu.

Acquisitions and Divestitures

In the month of May 2018, the Partnership executed two purchase and sale agreements to sell a small portion of its Delaware Basin acreage for $10.6 million. At the time of the divestiture, the sales represented approximately 29 Boe per day of production, less than 0.8% of total production and 59 net royalty acres, approximately 0.08% of total net royalty acres.

On May 28, 2018, we entered into securities purchase agreements to acquire all of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Resources, LP (the “Haymaker Acquisition”) in a transaction valued at approximately $445.4 million.  The purchase price for the Haymaker Acquisition was comprised of cash consideration of approximately $210.0 million and 10,000,000 common units of the Partnership, valued at approximately $235.4 million based on the closing price of $23.45 on July 12, 2018.  We raised the cash portion of the purchase price of the Haymaker Acquisition through a private placement of 7.0% Series A Cumulative Convertible Preferred Units (“Series A Preferred Units”) to an affiliate of Apollo Global Management, LLC for gross proceeds of $110.0 million (the “Preferred Units Transaction”) and through borrowings of $124.0 million under a new $200.0 million revolving credit facility (the “Credit Agreement Amendment”). The Haymaker Acquisition, the Preferred Units Transaction and the Credit Agreement Amendment closed on July 12, 2018. The effective date of the Haymaker Acquisition is April 1, 2018.

Following the closing of the Haymaker Acquisition, we owned mineral and royalty interests in approximately 11.0 million gross acres in 28 states, including ownership in over 84,000 gross producing wells, with over 38,000 wells in the Permian Basin. 

Second Quarter Common Unit Distribution.

On July 27, 2018, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.43 per common unit for the quarter ended June 30, 2018.   The distribution will be paid on August 13, 2018 to unitholders of record as of the close of business on August 6, 2018.  The common units issued in connection with the Haymaker Acquisition were included in the total outstanding units as of the date of record for the distribution.  Since the effective date of the Haymaker Acquisition was April 1, 2018, the Partnership was entitled to receive all net revenue from the properties included in the Haymaker Acquisition on and after April 1, 2018.  The Board of Directors elected to pay a portion of these net revenues in the second quarter common unit distribution.

Tax Election and Restructuring

In preparation for the Restructuring (as defined below), we formed and contributed all of our assets and liabilities to Kimbell Royalty Operating, LLC, our wholly owned subsidiary (the “Operating Company”).  Further, on July 24, 2018, we entered into a Recapitalization Agreement, dated as of July 24, 2018, by and among Haymaker Minerals & Royalties, LLC, Haymaker Management, LLC and certain affiliates of Haymaker Resources, LP (each of the preceding entities, the “Haymaker Holders”), Haymaker Resources, LP, the Kimbell Art Foundation, us, our general partner and the Operating Company, pursuant to which (i) our equity interest in the Operating Company will be recapitalized into 13,886,204 newly issued common units of the Operating Company (“OpCo Common Units”) and 110,000 newly issued Series A Cumulative Convertible Preferred Units of the Operating Company (“OpCo Series A Preferred Units”), (ii) the Haymaker Holders and the Kimbell Art Foundation will deliver and assign to us the 10,000,000 and 2,953,258 common units they own,

19


 

respectively, in exchange for (a) 10,000,000 and 2,953,258 newly issued Class B common units representing limited partner interests in us (the “Class B Units”), respectively, and (b) 10,000,000 and 2,953,258 newly issued OpCo Common Units, respectively, and (iii) we will amend and restate the limited liability company agreement of the Operating Company (the “Operating Company Agreement”) to reflect these transactions (collectively, the “Restructuring”). At the consummation of the Restructuring, we will enter into an exchange agreement with the Haymaker Holders, the Kimbell Art Foundation, our general partner and the Operating Company granting the Haymaker Holders and the Kimbell Art Foundation the right to exchange their OpCo Common Units and Class B Units for common units.

On July 26, 2018, we filed a preliminary Information Statement related to the  amendment and restatement of our partnership agreement in connection with our decision to change our United States federal income tax status from a pass-through “partnership” to an entity taxable as a “corporation” by means of a “check-the-box” election (the “Tax Election,” and, together with the Restructuring and related transactions described in the Information Statement, the “Up-C Transaction”) and an amendment to our Long-Term Incentive Plan.  Pursuant to Rule 14c-2 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the written consent will become effective on or after the date that is 20 calendar days following the date that the definitive information statement on Schedule 14C is first sent or given to our unitholders.

Business Environment

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. During the six months ended June 30, 2018, West Texas Intermediate (“WTI”) ranged from a low of $59.20 per Bbl on February 9, 2018 to a high of $77.41 per Bbl on June 27, 2018, and during the six months ended June 30, 2017, WTI ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $54.48 per Bbl on February 23, 2017. During the six months ended June 30, 2018, the Henry Hub spot market price of natural gas ranged from a low of $2.49 per MMBtu on February 16, 2018 to a high of $6.24 per MMBtu on January 3, 2018, and during the six months ended June 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. On July 30, 2018, the WTI posted price for crude oil was $71.19 per Bbl and the Henry Hub spot market price of natural gas was $2.75 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 six months ended June 30, 2018 and 2017:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30, 

 

Six Months Ended June 30, 

EIA Average Price:

 

2018

    

2017

 

2018

    

2017

Oil (Bbl)

 

$

68.07

 

$

48.10

 

$

65.55

 

$

49.85

Natural gas (MMBtu)

 

$

2.85

 

$

3.08

 

$

2.96

 

$

3.05

Rig Count

Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The Baker Hughes U.S. Rotary Rig count was 1,154 active rigs at June 30, 2018, a 23% increase from 940 active rigs at June 30, 2017. 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 22% from 862 active rigs at June 30, 2017 to 1,049 active rigs at June 30, 2018. The active rig count across our acreage at June 30, 2018 totaled 25 rigs, a 9% increase compared to the 23 rigs at March 31, 2018.  As of August 1, 2018 and after the closing of the Haymaker Acquisition, there were 72 active rigs working on our properties. 

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 June 30, 2018, our revenues were generated 61% from oil sales, 23% from

20


 

natural gas sales, 12% from NGL sales and 4% from other sales. For the three months ended June 30, 2017, our revenues were generated 58% from oil sales, 31% from natural gas sales and 11% from NGL sales. For the six months ended June 30, 2018, our revenues were generated 61% from oil sales, 23% from natural gas sales, 13% from NGL sales and 3% from other sales. For the period from February 8, 2017 to June 30, 2017, our revenues were generated 60% from oil sales, 29% from natural gas sales and 11% from NGL sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined six months ended June 30, 2017, the revenues were generated 60% from oil sales, 29% from natural gas sales and 11% from 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.

We entered into oil and natural gas commodity derivative agreements with Frost Bank beginning January 1, 2018 which extends through March 2020. Our Predecessor did not enter 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, our Predecessor may have realized the benefit of any short‑term increase in the price of oil, natural gas and NGLs, but was not protected against decreases in price, and if the price of oil, natural gas and NGLs decreased significantly, our Predecessor’s business, results of operation and cash available for distribution may have been materially adversely affected.

Non‑GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution

Adjusted EBITDA and cash available for distribution are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution are useful because they allow 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) before interest expense, net of capitalized interest, non‑cash unit‑based compensation, transaction costs, mark-to-market gains and losses on open commodity derivative instruments, impairment of oil and natural gas properties, income taxes and depreciation, depletion and accretion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by 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. We define cash available for distribution as Adjusted EBITDA, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

Adjusted EBITDA and cash available for distribution should not be considered an alternative to net income (loss), 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 and cash available for distribution may not be comparable to other similarly titled measures of other companies.

21


 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Three Months Ended June 30, 

 

Three Months Ended June 30, 

 

Six Months Ended June 30, 

 

Period from
February 8, 2017 to June 30, 

 

 

Period from
January 1, 2017 to February 7,

 

 

2018

 

2017

 

2018

 

2017

 

 

2017

Reconciliation of net income (loss) to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

1,378,295

 

$

251,651

 

$

(51,446,176)

 

$

534,869

 

 

$

(496,856)

Depreciation, depletion and accretion expense

 

 

3,431,594

 

 

4,131,717

 

 

7,887,302

 

 

6,667,377

 

 

 

113,639

Interest expense

 

 

483,558

 

 

182,975

 

 

833,600

 

 

243,127

 

 

 

39,307

EBITDA

 

 

5,293,447

 

 

4,566,343

 

 

(42,725,274)

 

 

7,445,373

 

 

 

(343,910)

Impairment of oil and natural gas properties

 

 

 —

 

 

 —

 

 

54,753,444

 

 

 —

 

 

 

 —

Transaction costs

 

 

1,188,967

 

 

 —

 

 

1,188,967

 

 

 —

 

 

 

 —

Unit‑based compensation

 

 

723,039

 

 

135,692

 

 

1,391,973

 

 

135,692

 

 

 

50,422

Change in fair value of open commodity derivative instruments

 

 

469,072

 

 

 —

 

 

681,530

 

 

 —

 

 

 

 —

Adjusted EBITDA

 

$

7,674,525

 

$

4,702,035

 

$

15,290,640

 

$

7,581,065

 

 

$

(293,488)

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash interest expense

 

 

502,811

 

 

105,625

 

 

977,487

 

 

109,539

 

 

 

34,505

Cash available for distribution

 

$

7,171,714

 

$

4,596,410

 

$

14,313,153

 

$

7,471,526

 

 

$

(327,993)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Three Months Ended June 30, 

 

Three Months Ended June 30, 

 

Six Months Ended June 30, 

 

Period from
February 8, 2017 to June 30, 

 

 

Period from
January 1, 2017 to February 7,

 

 

2018

 

2017

 

2018

 

2017

 

 

2017

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

6,894,754

 

$

5,826,652

 

$

14,188,843

 

$

8,578,040

 

 

$

186,719

Interest expense

 

 

483,558

 

 

182,975

 

 

833,600

 

 

243,127

 

 

 

39,307

Impairment of oil and natural gas properties

 

 

 —

 

 

 —

 

 

(54,753,444)

 

 

 —

 

 

 

 —

Amortization of loan origination costs

 

 

(15,625)

 

 

(15,625)

 

 

(31,250)

 

 

(26,042)

 

 

 

(4,241)

Amortization of tenant improvement allowance

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

 

2,864

Unit-based compensation

 

 

(723,039)

 

 

(135,692)

 

 

(1,391,973)

 

 

(135,692)

 

 

 

(50,422)

Change in fair value of open commodity derivative instruments

 

 

(469,072)

 

 

 —

 

 

(681,530)

 

 

 —

 

 

 

 —

Changes in operating assets and liabilities: