Kimbell Royalty Partners (KRP) 8-K/A Index to Financial Statements

Exhibit 99.1

PHILLIPS ENERGY PARTNERS
HOUSTON, TEXAS
DECEMBER 31, 2018 AND 2017

INDEX TO FINANCIAL STATEMENTS

PHILLIPS ENERGY PARTNERS

Combined Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm	3
Combined Balance Sheets as of December 31, 2018 and 2017	4
Combined Statements of Operations for the Years Ended December 31, 2018 and 2017	5
Combined Statements of Members’ Capital for the Years Ended December 31, 2018 and 2017	6
Combined Statements of Cash Flows for the Years Ended December 31, 2018 and 2017	7
Notes to the Combined Financial Statements	8

2

To the Board of Directors

and Members of Phillips Energy Partners

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Phillips Energy Partners (the Company) as of December 31, 2018 and 2017, and the related statements of operations, members’ capital, and cash flows for each of the years in the two-year period ended December 31, 2018, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material aspects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

The financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the applicable rules and regulations of the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

We have served as the Company’s auditor since 2015.

/s/ HEARD, MCELROY & VESTAL LLC

Shreveport, Louisiana

May 21, 2019

3

Phillips Energy Partners
Combined Balance Sheets
(in thousands)

	December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	6,790		$	1,424
Accounts receivable	5,899			3,313
Prepaid expenses and other current assets	2			75
Total current assets	12,691			4,812
Oil and natural gas properties:
Oil and natural gas properties, successful efforts method	166,565			166,712
Accumulated depletion and impairment	(112,634		)	(106,741		)
Oil and natural gas interests, net	53,931			59,971
Other assets:
Other non-current assets	6			9
Total other assets	6			9
Total assets	$	66,628		$	64,792
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	397			234
Line of credit payable	—			982
Total current liabilities	397			1,216
Members’ capital	66,231			63,576
Total liabilities and members’ capital	$	66,628		$	64,792

See accompanying notes to the combined financial statements.

4

Phillips Energy Partners

Combined Statements of Operations
(in thousands)

	For the Year Ended December 31,
	2018			2017
Revenues:
Oil, natural gas, and natural gas liquids sales	$	26,526		$	15,856
Lease bonus and other revenues	874			650
Total revenues	27,400			16,506
Operating costs and expenses:
Production and ad valorem taxes	1,380			847
Processing, transportation, and other	1,168			632
Depletion	5,886			5,304
Impairment of oil and natural gas properties	75			864
General and administrative	4,237			2,362
Total operating costs and expenses	12,746			10,009
Operating income	14,654			6,497
Other income (expense):
Gain (loss) on disposition of assets	12,029			(62		)
Interest expense	(29		)	(385		)
Interest income	2			2
Total other income (expense)	12,002			(445		)
Net income	$	26,656		$	6,052

See accompanying notes to the combined financial statements.

5

Phillips Energy Partners

Combined Statements of Members’ Capital
(in thousands)

Balance - December 31, 2016	$	61,700
Net income	6,052
Capital distributions	(4,176		)
Balance - December 31, 2017	$	63,576
Net income	26,656
Capital distributions	(24,001		)
Balance - December 31, 2018	$	66,231

See accompanying notes to the combined financial statements.

6

Phillips Energy Partners

Combined Statements of Cash Flows
(in thousands)

	For the Year Ended December 31,
	2018			2017
Cash flows from operating activities:
Net income	$	26,656		$	6,052
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion	5,886			5,304
Impairment of oil and natural gas properties	75			864
Amortization of debt issuance costs charged to interest expense	18			150
(Gain) loss on disposition of assets	(12,029		)	62
Changes in operating assets and liabilities:
Accounts receivable	(2,586		)	313
Prepaid expenses and other current assets	73			(56		)
Accounts payable	163			5
Accrued liabilities and other payables	—			(153		)
Net cash provided by operating activities	18,256			12,541
Cash flows from investing activities:
Proceeds from disposition of assets, net	12,108			85
Other, net	3			3
Net cash provided by investing activities	12,111			88
Cash flows from financing activities:
Repayments of borrowings under revolving credit facilities	(1,000		)	(11,350		)
Capital distributions	(24,001		)	(4,176		)
Net cash used in financing activities	(25,001		)	(15,526		)
Net increase (decrease) in cash and cash equivalents	5,366			(2,897		)
Cash and cash equivalents at beginning of year	1,424			4,321
Cash and cash equivalents at end of year	$	6,790		$	1,424
Supplemental disclosure of cash flow information:
Cash paid for interest	$	11		$	230

See accompanying notes to the combined financial statements.

7

Phillips Energy Partners

Notes to Combined Financial Statements

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

The combined financial statements presented herein include the accounts of Phillips Energy Partners, LLC, Phillips Energy Partners II, LLC, and Phillips Energy Partners III, LLC (collectively “Phillips Energy Partners”, the “Company”, or the “PEP Funds”). The three entities were formed to acquire and manage oil and natural gas mineral, royalty, and overriding interests. Management Services Agreements (“MSAs”) exist between the PEP Funds and Fortis Administrative Services, LLC (“Fortis”) whereby Fortis provides management, support, and administrative services with respect to the Company’s operations. In March 2019, the MSAs were terminated upon Kimbell Royalty Partners, LP’s (“Kimbell”) acquisition of the equity interests in the PEP Funds. A Transition Services Agreement (“TSA”) was entered into between Kimbell and Fortis whereby Fortis may continue to provide certain support services with respect to the PEP Funds through May 31, 2019, and with Kimbell having an option to extend through June 30, 2019 (see Note 11. Subsequent Events).

Unless the context requires otherwise, references to “we”, “us”, or “our” are intended to mean the business and operations of the Company.

Basis of Presentation

The Company’s combined financial statements reflect the financial statements of the PEP Funds on a combined basis for the periods presented. The Company’s combined financial statements were prepared in accordance with United States Generally Accepted Accounting Principles (“U.S. GAAP”). All significant intercompany items have been eliminated.

The following entities were determined to be under common control as of December 31, 2018 and represent the operations of the Company:

·Phillips Energy Partners, LLC (“PEP I”), was organized as a Delaware limited liability company on May 4, 2007. PEP I is engaged in the acquisition and management of oil and natural gas mineral, royalty, and overriding royalty interests in the United States. PEP I is wholly owned by two partnerships formed by EnCap Investments, LP (“EnCap”), which owned a 31.0% and 69.0% share, respectively. On July 1, 2016, pursuant to the amended and restated limited liability company agreement of PEP I, EnCap, as “Managing Member”, granted Fortis (“Incentive Member”) an incentive interest in PEP I.

·Phillips Energy Partners II, LLC (“PEP II”), was organized as a Delaware limited liability company on March 5, 2010. PEP II is engaged in the acquisition and management of oil and natural gas mineral, royalty, and overriding royalty interests in the United States. PEP II is wholly owned by a partnership formed by EnCap. On July 1, 2016, pursuant to the amended and restated limited liability company agreement of PEP II, EnCap, as “Managing Member”, granted Fortis (“Incentive Member”) an incentive interest in PEP II. PEP II has one wholly owned subsidiary (Cirrus Minerals, LLC).

·Phillips Energy Partners III, LLC (“PEP III”), was organized as a Delaware limited liability company on July 31, 2012. PEP III is engaged in the acquisition and management of oil and natural gas mineral, royalty, and overriding royalty interests in the United States. PEP III is wholly owned by a partnership formed by EnCap. On July 1, 2016, pursuant to the amended and restated limited liability company agreement of PEP III, EnCap, as “Managing Member”, granted Fortis (“Incentive Member”) an incentive interest in PEP III. PEP III has one wholly owned subsidiary (Mustang Minerals, LLC).

Segment Reporting

The Company operates in a single operating and reportable segment engaged in the management of oil and natural gas properties located in the United States. 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 Company’s chief executive officer was determined to be the chief operating decision maker and allocated resources and assessed performance based upon financial information of the Company as a whole.

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of 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 and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements

8

Phillips Energy Partners

Notes to Combined Financial Statements

and the reported amounts of revenues and expenses during the reporting period. The Company evaluates estimates and assumptions on an ongoing basis using historical experience and other factors. While we believe that the estimates and assumptions used in preparation of the financial statements are appropriate, because there are numerous uncertainties inherent in the estimation process, actual results could differ materially from those estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral, royalty, and overriding royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas, and natural gas liquids (“NGL”) reserves and related present value estimates of future net cash flows from those properties, and equity-based compensation.

Estimated proved oil, natural gas, and NGL reserve quantities and associated discounted and undiscounted cash flows are significant components of our depletion and proved property impairment calculations and require many subjective judgments. Estimates of reserves are forecasts based on engineering analyses and historical production information. 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 revisions will not be necessary in the future. Significant downward revisions could result in changes in depletion rates and proved property impairments representing non-cash charges to income.

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and short-term liquid investments with maturities of less than three months from the date of purchase. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any losses from such investments.

Accounts Receivable

The Company’s accounts receivable consist of revenue payments due to the Company from its mineral, royalty, and overriding royalty interests and are recorded at the amount due, less an allowance for doubtful accounts when applicable. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company did not write-off any of its accounts receivable and no allowance for doubtful accounts was deemed necessary during the years ended December 31, 2018 and 2017.

Revenue Recognition

The Company’s revenue is primarily derived from sales of oil, natural gas, and NGLs obtained by the operator of wells in which the Company owns a royalty interest. Revenue is recorded when title passes to the operator or purchaser. Royalty interest owners have no rights or obligations to explore, develop, or operate properties and do not incur any of the costs of exploration, development, and operation of the properties. Given the inherent time lag between when oil, natural gas, and NGL production and sales occur, and when operators or purchasers often make disbursements to royalty interest owners, a significant portion of our revenues may represent accrued revenue based on estimated net sales volumes.

Oil, natural gas, and NGL sales are recorded on a gross basis in the Combined Statements of Operations with production and ad valorem taxes, and processing, transportation, and other expenses separately recorded as part of “Operating costs and expenses”.

Revenues from lease bonuses are included within ��Lease bonus and other” in the Combined Statements of Operations. Lease bonuses are recorded upon receipt to the extent we have no ongoing obligations to perform (other than allowing access to the lease).

Oil and Natural Gas Properties

The Company invests primarily in mineral, royalty, and overriding royalty interests of oil and natural gas properties. Oil and natural gas producing activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties are capitalized. All general and administrative costs unrelated to acquisitions are expensed as incurred. Depletion of capitalized costs is recorded using the units-of-production method based on proved reserves. On the sale or retirement of a proved property, the cost and related accumulated depletion are removed from the property accounts, and any gain or loss is recognized.

9

Phillips Energy Partners

Notes to Combined Financial Statements

Reserves

Estimates of the Company’s proved reserves are prepared in accordance with U.S. GAAP and Securities Exchange Commission (“SEC”) guidelines. Our engineering estimates of proved oil, natural gas, and NGL reserves directly impact financial accounting estimates, including depletion and impairment of proved properties. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering, and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves. Reserve estimates at December 31, 2018 were based on the best estimates of the Company’s management. Ryder Scott Company (“Ryder Scott”), which are independent reserve engineers, were engaged to audit our reserves estimates at December 31, 2017. The properties audited by Ryder Scott accounted for approximately 84% of total proved developed reserves and total estimated proved discounted future net income.

Impairment of Long-Lived Assets

In accordance with ASC 360, Property, Plant, and Equipment, long-lived assets, such as property and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of the underlying properties include estimates of reserves, future commodity prices, and the market-based weighted average cost of capital rate. See Note 4. Property and Equipment for further details.

Long-lived assets classified as available for sale are separately presented in the Combined Balance Sheets and reported at the lower of the carrying amount or fair value less costs to sell and are no longer depleted.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, prepaid expenses, payables, and a line of credit payable. The carrying amounts of cash and cash equivalents, receivables, prepaid expenses, and payables approximates fair value because of the short-term nature of the instruments. The line of credit payable is carried at cost, which approximates fair value based on borrowing rates available to the Company for bank loans with similar terms and maturities (see Note 5. Fair Value).

Concentrations

The Company is subject to risks resulting from the concentration of its revenues in producing properties in the the Eagle Ford Shale in Texas, the Permian Basin in Texas and New Mexico, the Haynesville Shale in Texas and Louisiana, and the Marcellus/Utica Shales in Pennsylvania and West Virginia, as well as revenues derived from certain property operators. For the years ended December 31, 2018 and 2017, greater than 10% of revenues were generated from regions and specific operators as follows:

	For the Years Ended December 31,
	2018		2017
Regions:
Eagle Ford Shale (TX)	49	%	45	%
Permian Basin (TX/NM)	14	%	17	%
Haynesville Shale (TX/LA)	11	%	8	%
Marcellus/Utica Shale (PA/WV)	8	%	10	%
Operators:
EOG Resources, Inc.	22	%	30	%
Chesapeake Energy Corporation	12	%	11	%

10

Phillips Energy Partners

Notes to Combined Financial Statements

General and Administrative Expense

The PEP Funds have no employees. Separate MSAs were entered into between the PEP Funds and Fortis to provide management, support, and administrative services with respect to the Company’s operations. General and administrative (“G&A”) expenses include all direct company related expenses, as well as indirect expenses, including non-employee compensation for executives and other personnel allocated to the PEP Funds by Fortis (see Note 7. Related Party Transactions).

Equity-Based Compensation

The PEP Funds have granted equity-based compensation awards in the form of incentive interests. These awards are accounted for under authoritative guidance on share-based payments and stock compensation. The guidance requires all incentive interest awards to non-employees and directors to be recognized in the financial statements based on their fair values once performance and requisite service conditions are met. Based on their terms, the incentive interest awards granted by the PEP Funds are not deemed vested as specified performance and service conditions have not been met as of the end of the reporting periods and no equity-based compensation expense was recognized during the years ended December 31, 2018 and 2017 (see Note 10. Equity).

Income Taxes

The PEP Funds have elected to be taxed as partnerships. Accordingly, income taxes are assessed upon the PEP Funds’ owners for their share of taxable income or loss. However, the PEP Funds are required to review various tax positions taken with respect to the continued applicability of tax statuses as partnerships, and whether they are appropriately filing tax returns for all jurisdictions for which they have a tax nexus. The Company is subject to the Texas Franchise Tax, which is not a pass through item. The Texas Franchise Tax (commonly referred to as the Texas Margin Tax) is levied at a rate of 0.75% on applicable gross revenues less certain deductions, as specifically set forth in the Texas Margin Tax Statute.

Recently Issued Accounting Pronouncements

In June 2018, the FASB issued ASU 2018-07, Improvements to Non-employee Share-Based Payment Accounting, intended to simplify the accounting for share-based payments to non-employees by aligning it with the accounting for share-based payments to employees, with certain exceptions. The amendments in this ASU are effective for non-public business entities for fiscal years beginning after December 15, 2019, and interim periods beginning after December 15, 2020, with early adoption permitted. The Company did not early adopt ASU 2018-07, and we do not expect this update to have a material impact on the Company’s financial statements.

In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718). The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met:

·The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified.

·The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified.

·The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.

For non-public business entities, this ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. This update did not have a material impact on the Company’s financial statements.

In January 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether the transaction is a business acquisition under revised criteria. The ASU is effective for non-public business entities for fiscal years beginning after December 15,

11

Phillips Energy Partners

Notes to Combined Financial Statements

2018, and interim periods within fiscal periods beginning after December 15, 2019, with early adoption permitted under certain circumstances. The amendments in this ASU should be applied prospectively as of the beginning of the period of adoption. The Company does not plan to early adopt and we do not expect this update to have a material impact on the Company’s financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The new guidance is effective for non-public business entities for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. The Company does not plan to early adopt and we do not expect this update to have a material impact on the Company’s financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for non-public entities for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of the filing date, the Company was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this ASU. The Company does not plan to early adopt and we do not expect this update to have a material impact on the Company’s financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Asset and Financial Liabilities, intended to enhance the reporting model for financial instruments to provide users of financial statements with more decision-useful information. The amendments in ASU 2016-01 address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. For private business entities, the amendments in ASU 2016-01 are effective for fiscal years beginning after December 15, 2018, and for interim periods within fiscal years beginning after December 15, 2019. Early application to financial statements of fiscal years or interim periods that have not yet been issued is permitted as of the beginning of the fiscal year of adoption. The Company does not plan to early adopt and we do not expect this update to have a material impact on the Company’s financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and industry specific guidance in ASC Subtopic 932-605, Extractive Activities — Oil and Gas — Revenue Recognition. This ASU requires entities to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods and services. This ASU is effective for non-public business entities for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019, and is required to be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption, with early adoption permitted. The Company does not plan to early adopt and we do not expect this update to have a material impact on the Company’s financial statements.

3.ACQUISITIONS AND DISPOSITIONS

The Company did not make any acquisitions during the years ended December 31, 2018 and 2017.

In August 2018, the Company closed on the sale of certain interests in Texas to a third party for $12.0 million. The Company recorded a $11.9 million gain on sale, which is reflected in “(Gain) loss on disposition of assets” in the Combined Statement of Operations. The Company also closed on various other sales of properties during 2018 and 2017 for proceeds of $0.1 million and $0.1 million, respectively.

4.OIL AND NATURAL GAS PROPERTIES

The Company uses the successful efforts method of accounting for its investment in mineral, royalty, and overriding royalty interests. Under this method of accounting, proved and unproved property acquisition costs are capitalized as the cost of properties when incurred.

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Phillips Energy Partners

Notes to Combined Financial Statements

To the extent capitalized costs of proved properties, net of accumulated depletion, exceed the undiscounted future cash flows, the carrying value of the property is reduced to estimated fair value and the excess capitalized costs are charged to impairment expense in the period incurred. Proved properties are grouped for impairment purposes by regional aggregations of fields according to a number of factors including location and geological characteristics. The Company recognized impairment expenses associated with its proved properties of $38 thousand and $1 thousand for the years ended December 31, 2018 and 2017, respectively. The impairments were primarily due to changes in assumptions and reductions in estimated future cash flows and represent nonrecurring fair value measurements (see Note 5. Fair Value).

A portion of the carrying value of the Company’s interests is attributable to unproved properties. The unproved amounts are not subject to depletion until they are classified as proved properties. Capitalized costs attributable to the properties become subject to depletion when proved reserves are assigned to the property and the Company transfers the cost basis from unproved to proved properties accordingly. The Company assesses all properties classified as unproved on an annual basis for impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: recent drilling activity, remaining lease term, geological, geophysical and engineering evaluations, and market prices for similar assets. The Company recognized impairment expenses associated with its unproved properties of $0.04 million and $0.9 million for the years ending December 31, 2018 and 2017, respectively. The impairments were primarily due to recent drilling activity in certain areas.

The proved and unproved property impairments are reported in “Depletion and impairment” in the Combined Statements of Operations.

The following is a summary of property and equipment as of December 31, 2018 and 2017 (in thousands):

	December 31,
	2018			2017
Oil and natural gas interests:
Proved properties	$	130,598		$	129,455
Unproved properties	35,967			37,257
Gross oil and natural gas interests	166,565			166,712
Less accumulated depletion and impairment	(112,634		)	(106,741		)
Oil and natural gas interests, net	$	53,931		$	59,971

5.FAIR VALUE

ASC 820, Fair Value Measurements and Disclosures, defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and enhances disclosure requirements for fair value measurements. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company has applied ASC 820 to all financial instruments that are required to be reported at fair value.

Financial instruments are carried at fair value and are classified and disclosed in the following categories:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 consists of financial instruments whose fair values are estimated using quoted market prices.

Level 2 — Quoted prices for identical or similar assets or liabilities in markets that are less active, that is, markets in which there are few transactions for the asset or liability that are observable for substantially the full term. Included in Level 2 are those financial instruments for which fair values are estimated using models or other valuation methodologies. These models are primarily industry-standard models that consider various observable inputs, including time value, yield curve, volatility factors, observable current market and contractual prices for the underlying financial instruments, as well as other relevant economic measures.

Level 3 — Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity). Level 3 is comprised of financial instruments whose fair value is estimated based on internally developed models or methodologies utilizing significant inputs that are not readily observable for objective sources.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). A market is active if there are sufficient transactions

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Phillips Energy Partners

Notes to Combined Financial Statements

on an ongoing basis to provide current pricing information for the asset or liability, pricing information is released publicly, and price quotations do not vary substantially either over time or among market makers. Observable inputs reflect the assumptions market participants would use in pricing the asset or liability developed based on markets data obtained from sources independent of the reporting entity.

In determining the appropriate fair value hierarchy levels, the Company has performed an analysis of the financial assets and liabilities that are subject to fair value reporting under applicable U.S. GAAP. The carrying amounts of our cash and cash equivalents, receivables, prepaid expenses, and payables approximate fair value due to the short-term maturities of these assets and liabilities. The reported amounts of debt approximate fair value.

Nonrecurring Fair Value Measurements

In connection with our review of long-lived assets, if there is an indication of impairment and the estimated undiscounted future cash flows do not exceed the carrying value of the long-lived assets, then these assets are written down to their fair value. During 2018 and 2017, our oil and natural gas properties were reviewed for impairment and certain interests were found to be impaired. The factors used to determine fair value for purposes of impairment testing include, but are not limited to, estimates of proved reserves, development activity, future commodity prices, timing of future production, production costs, and a discount rate commensurate with the risk reflective of the lives remaining for the respective assets. Because these significant fair value inputs are typically not observable, we have categorized the amounts as Level 3 inputs.

6.INVESTMENT IN UNCONSOLIDATED AFFILIATES

As of December 31, 2018 and 2017, respectively, the Company has a 4.8% interest in WB Energy Partners, L.P. (“WB Energy”), which the Company acquired in February 2009. The Company’s investment in WB Energy is accounted for using the cost method. The carrying value as of December 31, 2018 and 2017, was $6 thousand and $9 thousand, respectively, and is included in “Other non-current assets” in the Company’s Combined Balance Sheets. See Note 11. Subsequent Events for sale of interest in WB Energy subsequent to December 31, 2018.

7.RELATED PARTY TRANSACTIONS

Transactions with Fortis

Fortis was engaged to perform all management related duties of the PEP Funds. Fortis pays the majority of general and administrative expenses on behalf of the Company and bills the PEP Funds periodically for reimbursement. G&A expenses billed to the Company from Fortis during the years ended December 31, 2018 and 2017, totaled $4.1 million and $2.3 million, respectively.

8.DEBT

PEP II Credit Agreement

At the beginning of 2017, the Company had a $50 million senior secured credit agreement (the “PEP II Credit Agreement”) with Iberia Bank with a maturity date of May 11, 2019, and a borrowing base of $3.45 million. The borrowing base was reduced to $1.75 million in June 2017. Also in June 2017, the Company paid down amounts outstanding in full under the PEP II Credit Agreement and the facility was terminated.

The PEP II Credit Agreement could be used for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility. Outstanding borrowings under the PEP II Credit Agreement were subject to borrowing base limitations based on the collateral value of the Company’s proved properties, subject to quarterly redeterminations. Borrowings under the PEP II Credit Agreement bore interest at the U.S. Prime Rate plus or minus an Applicable Margin per annum, which was calculated based on a borrowing base utilization percentage. The interest was subject to a minimum rate of 3.00% and a maximum rate of 3.50% for the periods presented. Commitment fees on the unused portion of borrowings available under the Credit Agreements were due quarterly at a rate of 0.5% of the unused facility. Amounts outstanding under The PEP II Credit Agreement were collateralized by the oil and natural gas interests of the Company. The PEP II Credit Agreement also contained certain restrictive covenants.

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Phillips Energy Partners

Notes to Combined Financial Statements

PEP III Credit Agreement

At December 31, 2017, the Company had a $100 million senior secured credit agreement (the “PEP III Credit Agreement”) with Iberia Bank with a maturity date of September 30, 2018. The borrowing base was reduced to $5.0 million in June 2017. At December 31, 2017, outstanding borrowings under the PEP III Credit Agreement were $1.0 million. In January 2018, the Company paid down amounts outstanding in full under the PEP III Credit Agreement and the facility was terminated.

The PEP III Credit Agreement could be used for borrowings and the issuance of letters of credit subject to a limit of the lesser of the facility amount or the borrowing base amount under the facility. Outstanding borrowings under the PEP III Credit Agreement are subject to borrowing base limitations based on the collateral value of the Company’s proved properties, subject to quarterly redeterminations. Borrowings under the PEP III Credit Agreements bear interest at the U.S. Prime Rate plus or minus an Applicable Margin per annum, which is calculated based on a borrowing base utilization percentage. The interest was subject to a minimum rate of 3.25% and a maximum rate of 4.50% for the periods presented. Commitment fees on the unused portion of borrowings available under the Credit Agreements are due quarterly at a rate of 0.5% of the unused facility. Amounts outstanding under The PEP III Credit Agreement are collateralized by the oil and natural gas interests of the Company. The PEP III Credit Agreement also contains certain restrictive covenants. The Company believes it was in compliance with all of the covenants under the PEP III Credit Agreement as of December 31, 2017.

Debt Issuance Costs

Costs associated with establishing the PEP II and PEP III Credit Agreements were amortized as interest expense on a straight-line basis over the respective terms of each facility. Net unamortized debt issuance costs were $0 and $18 as of December 31, 2018 and 2017, respectively, and are reflected as a reduction to the line of credit payable. Unamortized debt issuance costs were proportionally reduced with the borrowing base redeterminations during 2017. Additionally, all unamortized debt issuance costs associated with the PEP II Credit Agreement were written-off with the termination of the facility in June 2017 and all unamortized debt issuance costs associated with the PEP III Credit Agreement were written-off with the termination of the facility in January 2018.

Interest Expense

Interest expense totaled $0.03 million and $0.4 million for the periods ending December 31, 2018 and 2017, respectively.

9.COMMITMENTS AND CONTINGENCIES

As of December 31, 2018 and 2017, the Company is not party to any agreements containing future minimum lease commitments. Rental of office space and other non-cancellable operating leases are maintained at Fortis. Certain portions of those costs are allocated to the PEP Funds for reimbursement as part of Fortis’ management fees.

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues, title or ownership disputes, and other matters. Management believes it has complied with the various laws and regulations, administrative rulings, and interpretations.

The Company could become involved in disputes or legal actions arising in the ordinary course of business.

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Company’s financial condition, results of operations, or liquidity and no amounts have been accrued at December 31, 2018 and 2017.

10.EQUITY

There were no capital contributions during the years ended December 31, 2018 and 2017. During the years ended December 31, 2018 and 2017, capital distributions totaled $24.0 million and $4.2 million, respectively. See Note 11. Subsequent Events for additional capital distributions made subsequent to December 31, 2018.

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Phillips Energy Partners

Notes to Combined Financial Statements

Fortis Incentive Interests

Effective July 1, 2016, the PEP Funds entered into Amended and Restated Limited Liability Company agreements, (“AR LLCs”) between each PEP Fund and Fortis. The AR LLCs granted Fortis, the Incentive Member, an incentive interest in the PEP Funds. Each fund has a Managing Member (the respective EnCap fund) and the Incentive Member. Per the agreements, the PEP Funds will have two classes of membership interests, which are the managing interests held by the Managing Member and the incentive interests held by the Incentive Member. Furthermore, there are no references to any unit designations. The AR LLCs define the incentive interests as economic interests only in the PEP Funds and are therefore not associated with legal equity units in the companies. Moreover, there is no investment required and no voting, liquidation, or pre-emptive rights on the incentive interests. The AR LLCs define how cash and property distributions are to be handled and the associated hurdles (performance conditions) involved prior to the Incentive Member receiving such distributions. Each PEP Fund’s AR LLC agreement contains different performance conditions. As of December 31, 2018 and 2017, the performance obligation was not met, therefore no equity-based compensation expense has been recorded for the years ended December 31, 2018 and 2017. There were no cash payments made related to the incentive interests during the years ended December 31, 2018 and 2017.

11.SUBSEQUENT EVENTS

The Company has evaluated events that occurred subsequent to December 31, 2018, through May 21, 2019, which is the date the financial statements were available to be issued, in the preparation of its financial statements.

Capital Distributions

Capital distributions totaling $10.6 million have been made subsequent to December 31, 2018.

Acquisition of the PEP Funds by Kimbell Royalty Partners, LP

In February 2019, Kimbell agreed to acquire all of the equity interests in the PEP Funds from EnCap in exchange for 9.4 million common units in Kimbell Royalty Operating, LLC, the operating company of Kimbell. The transaction closed in March 2019. Upon closing of the transaction, the MSAs with Fortis and associated incentive interests were terminated. A TSA was entered into between Kimbell and Fortis whereby Fortis may continue to provide certain support services with respect to the PEP Funds through May 31, 2019, and with Kimbell having an option to extend through June 30, 2019.

Sale of Investment in WB Energy

In March 2019, the Company sold its investment in WB Energy to a third party for $5 thousand.

12.SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company has only one reportable operating segment, which is oil and natural gas producing activities in the United States. See the Company’s accompanying Combined Statements of Operations for information about results of operations for oil and natural gas producing activities.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion and impairment are as follows (in thousands):

	December 31,
	2018			2017
Oil and natural gas interests:
Proved properties	$	130,598		$	129,455
Unproved properties	35,967			37,257
Gross oil and natural gas interests	166,565			166,712
Less accumulated depletion and impairment	(112,634		)	(106,741		)
Oil and natural gas interests, net	$	53,931		$	59,971

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Phillips Energy Partners

Notes to Combined Financial Statements

Costs Incurred in Oil and Natural Gas Activities

There were no costs incurred in oil, natural gas, and NGL acquisition and development activities during the years ended December 31, 2018 and 2017.

Results of Operations from Oil, Natural Gas, and Natural Gas Liquids Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas, and NGLs (in thousands). It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Company.

	For the Year Ended December 31,
	2018			2017
Oil, natural gas, and natural gas liquids sales	$	26,526		$	15,856
Production and ad valorem taxes	(1,380		)	(847		)
Processing, transportation, and other	(1,168		)	(632		)
Depletion	(5,886		)	(5,304		)
Impairment of oil and natural gas properties	(75		)	(864		)
Results of operations from oil, natural gas, and natural gas liquids	$	18,017		$	8,209

The following tables summarize the net ownership interest in the proved oil, natural gas, and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas, and NGL reserves. Reserve estimates at December 31, 2018 and 2017 are based on the best estimates of the Company’s management. Ryder Scott Company (“Ryder Scott”), which are independent reserve engineers, were engaged to audit our reserves estimates at December 31, 2017. The properties audited by Ryder Scott accounted for approximately 84% of total proved developed reserves and total estimated proved discounted future net income.

The proved oil, natural gas, and NGL reserve estimates and other components of the standardized measure were determined in accordance with authoritative guidance of the FASB and the SEC.

Proved Oil, Natural Gas, and Natural Gas Liquids Reserve Quantities

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The Company does not record proved undeveloped reserves.

A barrel of oil equivalent (“BOE”) conversion ratio of six thousand cubic feet of natural gas per barrel of oil (6 Mcf/Bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

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Phillips Energy Partners

Notes to Combined Financial Statements

The Company’s net proved oil, natural gas, and NGL reserves, which represent proved developed reserves, and changes in net proved oil, natural gas, and NGL reserves attributable to the oil, natural gas, and NGL properties, which are located in multiple states (within the United States) are summarized below:

	Crude Oil and				Natural Gas
	Condensate		Natural Gas		Liquids		Total
	(MBbls)		(MMcf)		(MBbls)		(MBOE)
Net proved reserves at January 1, 2017	958		7,842		661		2,926
Revisions of previous estimates (1)	50		532		228		367
Extensions and discoveries (2)	189		1,164		86		469
Production	(206	)	(1,564	)	(68	)	(535	)
Net proved reserves at December 31, 2017	991		7,974		907		3,227
Revisions of previous estimates (1)	283		2,251		(11	)	647
Extensions and discoveries (2)	364		3,362		206		1,130
Sales of minerals in place (3)	(63	)	(212	)	(38	)	(136	)
Production	(272	)	(2,351	)	(115	)	(779	)
Net proved reserves at December 31, 2018	1,303		11,024		949		4,089

(1)Revisions represent changes in previous estimates, either upward or downward, resulting primarily from new information obtained from production history, the majority of which were attributable to properties located in the Haynesville Shale.

(2)Includes extensions and discoveries primarily related to active drilling on our acreage. For 2017, extensions and discoveries were primarily in the Eagle Ford Shale, Marcellus Shale, Haynesville Shale, and Permian Basin. For 2018, extensions and discoveries were primarily in the Haynesville Shale, Eagle Ford Shale, Niobrara Shale, and Permian Basin.

(3)Includes sales of mineral and royalty interests, primarily in Texas.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas, and NGL reserves of the properties is as follows (in thousands):

	For the Year Ended December 31,
	2018			2017
Future cash inflows	$	132,717		$	78,415
Future production costs	(8,112		)	(904		)
Future state margin taxes	(1,683		)	(1,014		)
Future net cash flows (1)	122,922			76,497
Less 10% annual discount to reflect timing of cash flows	(59,404		)	(36,163		)
Standardized measure of discounted future net cash flows	$	63,518		$	40,334

(1)Future net cash flows do not include the effects of income taxes on future results because the Company was not subject to U.S. federal income tax and certain state-level taxes at an entity level for the years ended December 31, 2018 and 2017. Accordingly, no provision for income taxes has been provided because taxable income was passed through to the Company’s equity holders.

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas, and NGLs adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2018 were $63.18 per barrel of crude oil, $2.53 per Mcf for natural gas, and $23.68 per barrel for NGLs. The average prices for 2017 were $47.66 per barrel for crude oil, $2.31 per Mcf for natural gas, and $18.84 per barrel for NGLs.

Future production costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes

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Phillips Energy Partners

Notes to Combined Financial Statements

in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas, and NGL reserve estimates.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas, and NGL reserves of the properties are as follows (in thousands):

	For the Year Ended December 31,
	2018			2017
Standardized measure - beginning of year	$	40,334		$	31,135
Sales, net of production costs	(23,979		)	(14,377		)
Net changes of prices and production costs related to future production	13,907			7,189
Extensions, discoveries and improved recovery, net of future production costs	18,023			6,007
Revisions of previous quantity estimates, net of related costs	10,333			4,702
Net changes in state margin taxes	(669		)	(235		)
Accretion of discount	4,033			3,114
Sales of reserves in place	(1,874		)	—
Timing differences and other	3,410			2,799
Standardized measure - end of year	$	63,518		$	40,334

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