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

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

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

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

 

 

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

 

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

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

 

 

 

KIMBELL ROYALTY PARTNERS, LP

FORM 10‑Q

TABLE OF CONTENTS

 

 

 

PART I – FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements (Unaudited)

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

NOTE 1—ORGANIZATION

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

On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing of the IPO. As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of the Predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. The mineral and royalty interests underlying the oil, natural gas and natural gas liquids (“NGL”) production revenues of the Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

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

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Segment Reporting

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

Management Estimates

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

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

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

Reclassification of Prior Period Presentation

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

Cash and Cash Equivalents

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

Accounts Receivable

Oil, natural gas and NGL receivables consist of revenue amounts due to the Partnership from its mineral and royalty interests. The Predecessor’s other current assets include amounts due as reimbursement for costs incurred by the Predecessor. Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. The Partnership estimates and records an allowance for doubtful accounts when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of September 30, 2017 and December 31, 2016, no allowance for doubtful accounts is deemed necessary based upon a review of current receivables and the lack of historical write offs.

Property and Equipment

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-

line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.

Oil and Natural Gas Properties

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

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

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

The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. The fair value of these acquired assets was based on the common units issued to the Contributing Parties, other than the Predecessor, multiplied by the IPO price per common unit plus the net proceeds of the IPO that were distributed to the Contributing Parties, excluding the value of any common units or net proceeds distributed to the Predecessor. In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined the fair value of the acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that we are required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of September 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, the Partnership considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO, and management affirmed that there has not been a material change to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at September 30, 2017 of $240.8 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $78.4 million for the period ending September 30, 2017. The Partnership will continue to assess the fair value of the acquired assets at each periodic reporting date to ensure inclusion in the ceiling calculation is not required through the December 31, 2017 reporting period, which is the period of the exemption extended by the SEC. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired. All of the Partnership’s oil and natural gas properties are subject to the full-cost ceiling test. No impairment expense was recorded for the period from February 8, 2017 to September 30, 2017.

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

for the three and nine months ended September 30, 2016, respectively, as a result of reductions in estimated proved reserves and commodity prices.

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

Proceeds from other dispositions of oil and natural gas properties are credited to the full-cost pool. No gains or losses were recorded for the period from February 8, 2017 to September 30, 2017, the Predecessor 2017 Period, or the nine months ended September 30, 2016.

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

Other Current Liabilities

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

Asset Retirement Obligations

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

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

Other Long-Term Liabilities

The Predecessor’s other long-term liabilities consist of a tenant improvement allowance granted at the effective date of the lease for the Partnership’s office space. This allowance was accounted for as a deferred incentive and was being amortized over the term of the lease as a reduction to rent expense. The deferred incentive was fully realized through the transactions that were completed in connection with the closing of the Partnership’s IPO and is not recognized in the Partnership’s financial statements.

Income Taxes

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

Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership and the Predecessor incurred de minimis amounts of state income taxes during 2017.

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

The Partnership and the Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to September 30, 2017, the Predecessor 2017 Period, and the nine months ended September 30, 2016, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions.

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

Concentration of Credit Risk

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

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

Revenue Recognition

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

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

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

Fair Value Measurements

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the accompanying unaudited consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future.

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if

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 8 for the summary of changes in the fair value of the Predecessor’s ARO for the Predecessor 2017 Period.

Recently Issued Accounting Pronouncements

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

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

In June 2016, the FASB issued ASU 2016‑13, “Measurement of Credit Losses on Financial Instruments.” ASU 2016‑13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Partnership does not believe this standard will have a material impact on its financial statements.

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

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

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

In February 2016, the FASB issued ASU 2016‑02, “Leases.” ASU 2016‑02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases.

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

Based upon the substantial completion of review of our contracts and analysis done so far, the Partnership has not identified any revenue streams that would be materially impacted and does not expect the adoption of this standard to have a material effect on the Partnership’s financial statements. Our approach includes performing a detailed review of each of our revenue streams and comparing our historical accounting policies to the new standard. The Partnership will continue to monitor specific developments for our industry as it relates to ASU 2014-09. The Partnership anticipates using the modified retrospective method to adopt the new standard.

 

NOTE 3—ACQUISITIONS

In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million gross acres (6,881 net royalty acres) for an aggregate purchase price of approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.

NOTE 4—LONG-TERM DEBT

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

The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facility also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control. As of September 30, 2017, the Partnership’s outstanding balance was $22.2 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of September 30, 2017.

During the period ended September 30, 2017, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% and Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the period from February 8, 2017 to September 30, 2017, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.51%.

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

NOTE 5—COMMON UNITS

On February 8, 2017, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the initial assets were contributed to the Partnership by the Contributing Parties at the time of the IPO. On May 12, 2017, the Partnership issued 163,324 restricted units under the LTIP.

On May 2, 2017, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

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

On August 9, 2017, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of (i) common units in an amount equal to $30,000 to certain non-employee directors of the Partnership under the LTIP, which were fully vested as of the grant date, and (ii) a total of 4,247 restricted units to certain consultants under the LTIP. Such grants were made on August 11, 2017.

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

NOTE 6—EARNINGS (LOSS) PER UNIT

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

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

 

 

NOTE 7—UNIT-BASED COMPENSATION

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

Distributions related to the restricted units are paid concurrently with our distributions for common units. The fair value of our restricted units issued under our LTIP to our employees and directors is determined by utilizing the market value of our common units on the respective grant date. The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs. The following table presents a summary of the Partnership’s unvested common units.

 

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

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

 

For the Predecessor 2017 Period and the nine months ended September 30, 2016, total compensation expense for awards under the Predecessor’s long-term incentive plan was $50,422 and $453,795, respectively, and is included general and administrative expenses in the accompanying unaudited consolidated statements of operations. In connection with the transactions that were completed at the closing of the Partnership’s IPO, the outstanding options to purchase membership units under the Predecessor’s long-term incentive plan expired and were not converted to units in the Partnership.

 

NOTE 8—ASSET RETIREMENT OBLIGATIONS

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

 

NOTE 9—RELATED PARTY TRANSACTIONS

In connection with the IPO, the Partnership entered into a management services agreement with Kimbell Operating, which entered into separate service agreements with Steward Royalties, LLC (“Steward Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”) pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective service agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective service agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders. During the three months ended September 30, 2017, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $100,000, $100,000, $30,000, $125,884 and $164,616, respectively. During the period from February 8, 2017 to September 30, 2017, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $266,667, $266,667, $80,000, $335,691 and $438,975, respectively. Certain consultants who provide services under the above mentioned management services agreements were granted restricted units under the Partnership’s LTIP on May 12, 2017.

During the Predecessor 2017 Period and the nine months ended September 30, 2016, the Predecessor Company’s activities included certain related party receivables and payables; however, such amounts were de minimis at December 31, 2016.

NOTE 10—ADMINISTRATIVE SERVICES

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

NOTE 11—COMMITMENTS AND CONTINGENCIES

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

NOTE 12—SUBSEQUENT EVENTS

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

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

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

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

 

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

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

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

Unless otherwise indicated in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for periods on or prior to February 7, 2017 refers only to Rivercrest, the predecessor for accounting purposes, and does not include the results of the Partnership as a whole. The interests underlying the oil, natural gas and natural gas liquids(“NGL”) production revenues of our Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

Cautionary Statement Regarding Forward‑Looking Statements

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

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

Overview

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

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

Recent Developments

In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres, for an aggregate purchase price of approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its revolving credit facility.

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

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

 

Business Environment

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. In late 2014, prices for oil and natural gas declined precipitously, and prices remained low throughout 2015 and for the majority of 2016 until rebounding in the fourth quarter of 2016. During the nine months ended September 30, 2017, West Texas Intermediate (“WTI”) ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $54.48 per Bbl on February 23, 2017, and during the nine months ended September 30, 2016, WTI ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $51.23 per Bbl on June 8, 2016. During the nine months ended September 30, 2017, the Henry Hub spot market price of natural gas ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017. During the nine months ended September 30, 2016, the Henry Hub spot market price of natural gas ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $3.19 per MMBtu on September 21, 2016. On October 30, 2017, the WTI posted price for crude oil was $54.11 per Bbl and the Henry Hub spot market price of natural gas was $2.94 per MMBtu.

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

Source: EIA

Rig Count

The Baker Hughes U.S. Rotary Rig count was 940 active rigs at September 29, 2017, an 80% increase from 522 active rigs at September 30, 2016. In addition, according to the Baker Hughes U.S. Rotary Rig count, rig activity in the 20 states in which we own mineral and royalty interests increased 83% from 468 active rigs at September 30, 2016 to 857 active rigs at September 29, 2017. The active rig count across our acreage at October 31, 2017 totaled 21 rigs, a 40% increase compared to the 15 rigs at year-end 2016.

Sources of Our Revenue

Our revenues and our Predecessor’s revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. For the three months ended September 30, 2017, our revenues were generated 57% from oil sales, 30% from natural gas sales, 11% from NGL sales and 2% from other sales. For the three months ended September 30, 2016, our Predecessor’s revenues were generated 60% from oil sales, 30% from natural gas sales and 10% from NGL sales. For

the period from February 8, 2017 to September 30, 2017, our revenues were generated 59% from oil sales, 29% from natural gas sales, 11% from NGL sales and 1% from other sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined nine months ended September 30, 2017, the revenues were generated 58% from oil sales, 30% from natural gas sales, 11% from NGL sales and 1% from other sales. For the nine months ended September 30, 2016, our Predecessor’s revenues were generated 61% from oil sales, 29% from natural gas sales and 10% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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

Adjusted EBITDA

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

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

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

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