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

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑Q

Commission file number: 001‑38005

Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)

 

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)

Securities registered pursuant to Section 12(b) of the Exchange Act:

 

Securities registered pursuant to Section 12(g) of the Exchange Act: None

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑Q or any amendment to this Form 10‑Q. ☒

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.

 

 

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 May 10, 2017, 16,332,708 common units of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

 

KIMBELL ROYALTY PARTNERS, LP

TABLE OF CONTENTS

 

 

 

 

 

PART I – FINANCIAL INFORMATION

Item 1.  Financial Statements

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(unaudited)

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

 

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

 

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

KIMBELL ROYALTY PARTNERS, LP

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

(unaudited)

 

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

 

 

 

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

 

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

 

 

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

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

 

NOTE 1—ORGANIZATION

 

Kimbell Royalty Partners, LP was formed on October 30, 2015. The Partnership adopted a fiscal year-end of December 31. 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.

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

The Predecessor is a Delaware limited liability company formed on October 25, 2013, an owner of oil, natural gas and natural gas liquids mineral and royalty interests in the United States of America (‘‘United States’’). In addition to mineral and royalty interests, the Predecessor’s assets include overriding royalty interests. These non-cost-bearing interests are collectively referred to as ‘‘mineral and royalty interests.’’ The Predecessor also had non-operated working interests in certain oil and natural gas properties. Prior to the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated asset retirement obligations to a third party.

 

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 (“U.S. GAAP”) and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP.  Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with

the Partnership’s and 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 U.S. GAAP.  The results of operations for the period from February 8, 2017 to March 31, 2017 are not necessarily indicative of the results to be expected for the full year.

Segment Reporting

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

Management Estimates

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

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

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in an 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 consists of revenue payments due to the Partnership from the mineral and royalty interests. The Predecessor’s other receivables are amounts due as reimbursement for costs incurred by the Predecessor.  Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership was entitled to receive royalty payments with respect to the acquired properties from and after February 1, 2017.  Included in oil, natural gas and NGL receivables are payments due to us by our Contributing Parties for oil, natural gas and NGL production contained in operator checks dated after the effective date of our IPO and containing production related to months prior to the effective date of the IPO.  As of March 31, 2017, amounts due to the Partnership from the Contributing Parties were $2.5 million.  The Partnership estimates and

records an allowance when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of March 31, 2017 and December 31, 2016, no allowance for doubtful accounts is deemed necessary based upon the lack of historical write offs and a review of current receivables.

Property and Equipment

Other property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease. Depreciation expense for the period from January 1, 2017 to February 7, 2017 and for the period from February 8, 2017 to March 31, 2017 was $6,166 and $26,423, respectively, for a combined depreciation expense of $32,589 for the three months ended March 31, 2017.     As of March 31, 2017 and December 31, 2016, property and equipment consisted of the following:

 

Oil and Natural Gas Properties

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

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

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

No impairment expense was recorded for the period from February 8, 2017 to March 31, 2017.  The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO.  The fair value of these acquired assets was based on the value of the common units issued to the Contributing Parties, other than the Predecessor, multiplied by the IPO price plus the net proceeds of the IPO that were distributed to the Contributing Parties, other than 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 at March 31, 2017, and requested and received an exemption from the SEC to exclude the recently acquired properties from the ceiling test calculation.  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 these recently acquired properties 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 recently acquired properties have

an unamortized cost at March 31, 2017 of $247.8 million.  Had these recently acquired properties been subject to the full cost ceiling test, the Partnership would have recorded an impairment charge of $91.3 million for the period ending March 31, 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, the period of the exemption provided by the SEC.

No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017.  During the three months ended March 31, 2016, the Predecessor recorded a full cost ceiling impairment charge of $3.7 million for the three months ended March 31, 2016, as a result of reductions in estimated proved reserves and reduced commodity prices.     

The Partnership’s properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and natural gas liquids reserves. Sales or other dispositions of oil and 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, natural gas and natural gas liquids properties are credited to the full cost pool. No gains or losses were recorded for the periods from January 1, 2017 to February 7, 2017, from February 8, 2017 to March 31, 2017 or for the three months ended March 31, 2016.

Due to the nature of the Predecessor’s and the Partnership’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the periods from January 1, 2017 to February 7, 2017, from February 8, 2017 to March 31, 2017 or for the three months ended March 31, 2016.

Asset Retirement Obligations

Prior to the formation transactions that were completed in connection with the IPO of the Partnership, the Predecessor assigned its non-operated working interests and associated asset retirement obligations to an affiliated company.  The Predecessor’s asset retirement obligation (‘‘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 formation transactions that were completed in connection with the IPO of the Partnership and is not recognized in the Partnership’s financial statements.

Income Taxes

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

Texas imposes a franchise tax (commonly referred to as the Texas margin tax, which is considered an income tax) at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. During the periods from January 1, 2017 to February 7, 2017 and from February 8, 2017 to March 31, 2017, the

Predecessor and the Partnership did not pay any state income taxes.  The Predecessor and the Partnership incurred state income taxes during the periods from January 1, 2017 to February 7, 2017 and from February 8 to March 31, 2017, respectively, however, such amounts were de minimis during the periods from January 1, 2017 to February 7, 2017 and from February 8, 2017 to March 31, 2017.  For the three months ended March 31, 2016, the Predecessor incurred income taxes in Texas and other states amounting to $5,885.

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 March 31, 2017 and December 31, 2016, respectively.

The Predecessor and the Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the period from January 1, 2017 to February 7, 2017, the period from February 8, 2017 to March 31, 2017 and for the three months ended March 31, 2016, the Predecessor and the Partnership did not recognize any interest or penalty expense related to uncertain tax positions.

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

Concentration of Credit Risk

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

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

Revenue Recognition

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

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

To the extent actual volumes and prices of oil, natural gas and natural gas liquids are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within oil, natural gas and NGL receivables in the accompanying consolidated balance sheet. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.

Fair Value Measurements

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

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

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 7 for the summary of changes in the fair value of the Predecessor’s ARO for the period from January 1, 2017 to February 7, 2017.

Recently Issued Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017‑04, "Simplifying the Test of Goodwill Impairment." ASU 2017‑04 simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill (Step 2 of the current goodwill impairment test). Instead, a company would record an impairment charge based on the excess of a reporting unit’s carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. Entities will apply the standard’s provisions prospectively. The Partnership does not believe this standard will have a material quantitative effect on the 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 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 does not believe this standard will have a material impact on its financial statements.

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 is evaluating the new guidance and has not determined the impact this standard may have on its financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue From Contracts with Customers’ (TOPIC 606).” an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (‘‘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.

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. The Partnership is still evaluating the impact that the new accounting guidance will have on its financial statements and related disclosures and has not yet determined the method by which it will adopt the standard.

 

 

NOTE 3—LONG-TERM DEBT

In connection with its IPO, the Partnership entered into a $50.0 million revolving credit facility which is secured by substantially all of its assets and the assets of its 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 the Partnership’s oil and natural gas properties and the oil and gas properties of the its wholly owned subsidiaries. The oil and gas properties of the Partnership’s non‑wholly owned subsidiaries are not subject to a lien and are not included in borrowing base valuations. 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 revolving credit facility matures on February 3, 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 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 March 31, 2017, the Partnership’s outstanding balance was $3.9 million.

During the period ended March 31, 2017, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25%.  As of March 31, 2017, the interest rate on the Partnership’s outstanding borrowings was 3.238%.  The Partnership was in compliance with all of the covenants included in the credit facility as of March 31, 2017.

On January 31, 2014, the Predecessor entered into a credit agreement with Frost Bank for up to a $50 million revolving credit facility.  The credit facility was subject to borrowing base restrictions and was collateralized by certain properties.  The borrowing based on the Predecessor’s credit facility was $20 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 4—COMMON UNITS

Kimbell Royalty Partners, LP

 

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 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.  As of March 31, 2017, 16,332,708 common units of the Partnership were outstanding.

 

NOTE 5—EARNINGS PER UNIT

The Partnership’s earnings per unit (‘‘EPU’’) on the consolidated statements of operations is based on the net income of the Partnership for the period from February 8, 2017 to March 31, 2017.  The Predecessor’s EPU on the statements of operations is based on the net loss of the Predecessor for the period from January 1, 2017 to February 7, 2017 and for the three months ended March 31, 2016, since this is the amount of net loss that is attributable to the Predecessor’s membership interests. 

Basic EPU is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested common units granted under the Predecessor’s long-term incentive plan described in Note 6—Unit-Based Compensation. The Partnership has no potentially dilutive securities and, as such, basic and diluted net income per common unit are the same. For the periods ended February 7, 2017 and March 31, 2016, the effect of the 110,000 options issued under the Predecessor’s long-term incentive plan would be anti-dilutive. Therefore, the options issued under the Predecessor’s long-term incentive plan were not included in the diluted EPU calculation on the statements of operations.

 

 

NOTE 6—UNIT-BASED COMPENSATION

As of March 31, 2017, the Partnership had not issued any units under its long term incentive plan or incurred unit-based compensation as described in its long term incentive plan. 

 

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.

The fair value of each Predecessor option award was estimated on the date of grant using the Black-Scholes option pricing model and using certain assumptions. The risk-free interest rate represented the U.S. Treasury bill rate for the expected life of the related unit options. The expected distribution represented the Predecessor’s historical and

anticipated cash distributions over the expected life of the unit options. The grant date fair value of the options was $27.50 per unit, based on a grant date of October 1, 2014, which was determined with the following assumptions:

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

 

For the period from January 1, 2017 to February 7, 2017 and for the three months ended March 31, 2016, total compensation expense for awards under the Predecessor’s long-term incentive plan was $50,422 and $151,265 respectively, and is included general and administrative expenses in the statements of operations.  In connection with the formation transactions that were completed at the IPO of the Partnership, the outstanding membership units under the Predecessor’s long-term incentive plan expired and were not converted to units in the Partnership.

 

 

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

 

Prior to the formation transactions that were completed in connection with the IPO, the Predecessor assigned its non-operated working interests and associated asset retirement obligations to a third party. As of the closing of its IPO and through the date of this report on Form 10-Q, the Partnership did not own any working interests and did not have any asset retirement obligations (‘‘ARO’’) or any lease operating expenses as a working interest owner.

 

The Predecessor’s ARO liability reflected the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Predecessor’s non-operated working interest in oil, natural gas and natural gas liquids properties. The Predecessor utilized current retirement costs to estimate the expected cash outflows for retirement obligations. The Predecessor estimated the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. The following table describes changes to the Predecessor’s ARO liability:

 

 

 

NOTE 8—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 period from February 8, 2017 to March 31, 2017, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $66,667, $66,667, $20,000, $83,923 and $109,744, respectively.

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

 

NOTE 9—ADMINISTRATIVE SERVICES

The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business efforts. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the General Partner’s Board of Directors and their affiliated entities.  See Note 8-Related Party Transactions.

 

NOTE 10—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 11—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to March 31, 2017 in the preparation of its consolidated financial statements.

On April 24, 2017, the Partnership announced the closing of the acquisition of 1.1 million gross acres (6,700 net royalty acres) of overriding royalty interests in the Anadarko Basin from Maxus Energy Corporation for $15.9 million.  As of March 31, 2017, the Partnership had a $2.4 million deposit on oil and natural gas properties related to this acquisition.

 

On May 2, 2017, the board of directors of the General Partner, declared a quarterly cash distribution of $0.23 per common unit for the quarter ended March 31, 2017.  The distribution will be 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 May 5, 2017, the Conflicts Committee (“the Committee”) and the Board of Directors (“the Board”) of Kimbell Royalty GP, LLC approved a form of Restricted Unit Agreement (the “Agreement”) contingent grant to be used

in connection with grants to be made under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan.  In connection with the approval of the Agreement, the Committee and the Board also approved the contingent grant and issuance of restricted units under the Plan, which approval was conditioned upon the Partnership’s filing with the Securities and Exchange Commission of a Registration Statement on Form S-8.  The Partnership plans to file the Registration Statement during the second quarter of 2017.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of financial condition and results of operations should be read together  in conjunction with our unaudited financial statements and notes thereto presented in this Quarterly Report on Form  10-Q (this “Quarterly Report”), as well as the historical financial statements of our accounting Predecessor for accounting and financial reporting purposes, Rivercrest Royalties, LLC, (“Rivercrest” or “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 our initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up our initial assets were contributed to us by certain entities and individuals, including affiliates of our founders (our “Sponsors”), that contributed them, directly or indirectly, to us (the “Contributing Parties”) at the time of our IPO. As a result, as of December 31, 2016, we had not yet acquired any of such assets.

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

 

Cautionary Statement Regarding Forward‑Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q 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:

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

Overview

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

As of March 31, 2017, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 0.9 million gross acres, with approximately 44% 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 March 31, 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 48,000 gross producing wells, including over 29,000 wells in the Permian Basin.

Recent Developments

On April 24, 2017, we announced the closing of the acquisition of 1.1 million gross acres (6,700 net acres) of overriding royalty interests in the Anadarko Basin from Maxus Energy Corporation for $15.9 million.  As of March 31, 2017, we had a $2.4 million deposit on oil and natural gas properties related to this acquisition.

 

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 three months ended March 31, 2017, WTI ranged from a low of $47.00 per Bbl on March 23, 2017 to a high of $54.48 per Bbl on February 23, 2017, and during the three months ended March 31, 2016, WTI ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $41.45 per Bbl on March 22, 2016.  During the three months ended March 31, 2017, the Henry Hub spot market price of natural gas has ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017.  During the three months ended March 31, 2016, Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $2.54 per MMBtu on January 11, 2016.  On May 8, 2017, the WTI posted price for crude oil was $46.46 per Bbl and the Henry Hub spot market price of natural gas was $3.06 per MMBtu.

The following table, as reported by the U.S. Energy Information Administration (“EIA”), sets forth the monthly spot price averages for oil and natural gas as of March 31, 2017 and 2016:

Source: EIA.

Rig Count

The Baker Hughes U.S. Rotary Rig count was 824 active rigs at March 31, 2017, a greater than 83% increase from 450 active rigs at April 1, 2016.  In addition, according to the Baker Hughes U.S. Rotary Rig count, rig activity in the 20 states in which we own mineral and royalty interests increased more than 87% from 401 active rigs at April 1, 2016 to 750 active rigs at March 31, 2017.

Sources of Our Revenue

Our Predecessor’s and our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and natural gas liquids production, as well as the sale of natural gas liquids that are extracted from natural gas during processing.  For the period from January 1, 2017 to February 7, 2017, our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from natural gas liquids sales. For the period from February 8, 2017 to March 31, 2017, our revenues were generated 62% from oil sales, 27% from natural gas sales and 11% from natural gas liquids sales. For the combined three months ended March 31, 2017, the revenues were generated 61% from oil sales, 28% from natural gas sales and 11% from natural gas liquids sales.  For the quarter ended March 31, 2016, our Predecessor’s revenues were generated 58% from oil sales, 31% from natural gas sales and 11% from natural gas liquids sales.  Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Neither we nor our Predecessor entered into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas and natural gas liquids produced from our mineral and royalty interests. As a result, we may realize the benefit of any short‑term increase in the price of oil, natural gas and natural gas liquids, but we will not be protected

against decreases in price, and if the price of oil, natural gas and natural gas liquids decreases significantly, our business, results of operation and cash available for distribution may be materially adversely effected. We may enter into hedging arrangements in the future.

Adjusted EBITDA

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

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

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

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

 

 

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

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

No Effect Given to Formation Transactions in connection with Initial Public Offering

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

The historical financial data of our Predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the Partnership and may not provide an accurate indication of what our actual results would have been if these formation transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The mineral and royalty interests of our Predecessor only represent approximately 11% of our partnership’s 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 gas prices increase the cost center ceiling applicable to the subsequent period.

During the three months ended March 31, 2016, our Predecessor recorded non-cash impairment charges of approximately $3.7 million primarily due to changes in reserve values resulting from the drop in commodity prices and other factors. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are taken.

No impairment expense was recorded for the period from February 8, 2017 to March 31, 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 acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt at March 31, 2017 and requested and received an exemption from the SEC to exclude the recently acquired properties from the ceiling test calculation.  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 these recently acquired properties was based on forward strip oil and natural gas pricing existing at the date of the IPO and management has affirmed that there has not been a material change to the oil and natural gas prices in the time since the IPO.  The recently acquired properties have an unamortized cost at March 31, 2017 of $247.8 million.  Had these recently acquired properties been subject to the full cost ceiling test, we would have recorded an impairment charge of $91.3 million for the period ending March 31, 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, the period of the exemption extended by the SEC.

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 March 31, 2017, we had borrowed $3.9 million to fund certain transaction related expenses and our entrance into a management services agreement with Kimbell Operating Company, LLC and to fund the deposit on our acquisition of 1.1 million gross acres (6,700 net royalty acres) of overriding royalty interests in the Anadarko Basin from Maxus Energy Corporation.  For the period from February 8, 2017 to March 31, 2017, we incurred $60,152 in interest expense.

In January 2014, our Predecessor entered into a credit agreement with Frost Bank, as lender. For the three months ended March 31, 2016 and for the period from January 1, 2017 to February 7, 2017 our Predecessor’s interest expense was $105,288 and $39,307, respectively. Our Predecessor had outstanding borrowings of $10.6 million as of December 31, 2016 and $10.6 million as of February 7, 2017.  We did not assume any indebtedness of our Predecessor in connection with the IPO.