Document

Exhibit 99.3

BPP ENERGY PARTNERS LLC

AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

AND INDEPENDENT AUDITORS’ REPORT

December 31, 2020 and 2019

CONTENTS


			Page

INDEPENDENT AUDITORS’ REPORT			1

CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets			2
Consolidated Statements of Operations			3
Consolidated Statements of Changes in Members’ Equity			4
Consolidated Statements of Cash Flows			5
Notes to the Consolidated Financial Statements			6

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)			20

INDEPENDENT AUDITORS’ REPORT

To the Board of Managers of BPP Energy Partners LLC

Dallas, Texas

We have audited the accompanying consolidated financial statements of BPP Energy Partners LLC and its subsidiaries (the "Company"), which comprise the consolidated balance sheets as of December 31, 2020 and 2019, and the related consolidated statements of operations, changes in members’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits 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 consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPP Energy Partners LLC and its subsidiaries as of December 31, 2020 and 2019, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

March 31, 2021

BPP ENERGY PARTNERS LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31

(in thousands)


	2020	2019
Assets
Current Assets
Cash and cash equivalents	$3,116	$14,758
Revenue receivable	6,752	14,692
Commodity derivatives	6,060	236
Prepaid and other	19,520	97
Total current assets	35,448	29,783

Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting	87,383	237,416
Unproved property and uncompleted capital projects excluded from amortization	—	5,681
Total oil and gas properties, net	87,383	243,097

Commodity derivatives	2,809	153
Loan origination cost, net	232	235
Investment in SFS	20,339	21,100
Total Assets	$146,211	$294,368

Liabilities and Members’ Equity
Current Liabilities
Accounts payable	$—	$49
Accounts payable - affiliate	972	9,906
Other current liabilities	12,329	8,155
Commodity derivatives	76	2,623
Total current liabilities	13,377	20,733

Line of credit	—	—
Term loan, net	73,537	73,167
Commodity derivatives	1,868	1,165
Asset retirement obligation	763	523
Total Liabilities	89,545	95,588

Commitments and contingencies (Note 10)

Members’ Equity	56,666	198,780

Total Liabilities and Members’ Equity	$146,211	$294,368

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

BPP ENERGY PARTNERS LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

THE YEARS ENDED DECEMBER 31

(in thousands)


	2020	2019
Revenues
Oil sales	$42,544	$54,241
Natural gas sales	1,128	1,372
Gain (loss) on derivative instruments, net	34,279	(4,672)
Total revenues	77,951	50,941

Costs and expenses
Lease operating expenses	12,539	13,207
Repairs	1,503	727
Production taxes	2,126	2,604
Depreciation, depletion and amortization	28,660	20,615
Impairment of oil and gas properties	163,223	—
General and administrative	3,273	2,536
Total operating expenses	211,324	39,689

(Loss) income from operations	(133,373)	11,252

Other income (expense)
Interest expense	(7,980)	(7,543)
Equity in (loss) earnings of SFS	(550)	47,942

Net (loss) income	($141,903)	$51,651

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

BPP ENERGY PARTNERS LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF

CHANGES IN MEMBERS’ EQUITY

(in thousands)


						Total Equity

Balance, January 1, 2019						$147,129

Net income						51,651

Balance, December 31, 2019						$198,780

Purchase of interest from related party by SFS						(211)

Net (loss)						(141,903)

Balance, December 31, 2020						$56,666

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

BPP ENERGY PARTNERS LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

THE YEARS ENDING DECEMBER 31

(in thousands)


Cash flow from operating activities	2020	2019
Net (loss) income	($141,903)	$51,651
Adjustments to reconcile net (loss) income to cash used in operating activities:
Depreciation, depletion, and amortization	28,660	20,615
Impairment of oil and gas properties	163,223	—
Deferred loan cost amortization	437	355
Unrealized (gain) loss on derivative instruments	(10,324)	4,644
Equity in loss (earnings) of SFS	550	(47,942)
Distributed equity in earnings of SFS	—	48,977
Changes in operating assets and liabilities:
Accounts receivable	7,940	(11,287)
Accounts payable	(49)	(548)
Accounts payable - affiliate	(9,183)	2,120
Prepaid and other current assets	(19,423)	(97)
Other liabilities	(3,837)	(8,700)
Net cash provided by operating activities	16,091	59,788

Cash flow from investing activities
Additions to oil and gas properties	(27,669)	(104,446)
Purchase of equity in SFS, an equity method investment	—	(8,759)
Return of capital from SFS, an equity method investment	—	12,047
Net cash used in investing activities	(27,669)	(101,158)

Cash flow from financing activities
Proceeds from line of credit	—	45,000
Repayment of line of credit	—	(45,000)
Proceeds from term loan	—	50,000
Capitalized loan cost	(64)	(821)
Net cash (used in) provided by financing activities	(64)	49,179

Net change in cash and cash equivalents	(11,642)	7,809

Cash and cash equivalents, beginning of period	14,758	6,949

Cash and cash equivalents, end of period	$3,116	$14,758

Supplemental cash disclosures:
Property additions included in accrued liabilities	$8,260	$8,713
Asset retirement obligations incurred, including revisions to estimates	$197	$341
Cash paid for interest	$7,593	$7,208

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

BPP ENERGY PARTNERS LLC AND SUBSIDARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION

BPP Energy Partners LLC (“BPP” or the “Company”), a Delaware limited liability company, was formed on October 16, 2018 to indirectly hold the operations of BPP Acquisition LLC (“BPP Acquisition”).

On November 27, 2018, BPP Energy Finance LLC (“BPP EF”) was formed as a wholly owned subsidiary of BPP for the purpose of obtaining term loan financing for use in the operations of BPP. BPP EF is the borrower of the term loan and owns all of the interest in BPP Acquisition.

BPP Acquisition was formed on May 4, 2017, and is engaged in the acquisition, development, production, and exploration of crude oil and natural gas properties located in Texas. As the formation of BPP and BPP EF were created as a reorganization of entities under common control, all prior period balances included in these financials are those of BPP Acquisition.

The Company was formed with two classes of Member Interest consisting of Common Interest and Profits Interest. These interests include the Series A Profits Interest, and two series of Common Interest, the Series B Common Interest and Series C Common Interest. The Company’s Series B shareholders are owned by funds controlled by The Blackstone Group L.P. (“Blackstone”) and have a commitment to fund $300 million. Series C common interest holders have a commitment to fund $34.8 million (see Note 7 for detail on membership interest types). As of December 31, 2020, there is $171.1 million and $19.9 million of the above commitment remaining to be funded for the Series B Common and Series C Common, respectively.

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These financial statements include the accounts of BPP Energy Partners, LLC and its subsidiaries: (i) BPP EF, and (ii) BPP Acquisition (collectively referred to as the Company). Intercompany transactions and balances have been eliminated upon consolidation.

On July 11, 2018, the Company purchased approximately 22% of its interest in Saragosa Field Services, LLC (“SFS”) from Primexx Energy Partners, Ltd. (“PEP”) an affiliated entity. During 2019, the Company purchased an additional 8% of its interest in SFS from PEP. Total purchased through the balance sheet date is 30%. Given that the Company does not have control over SFS, but has significant influence, it is treated as an equity method investment (see Note 4).

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates, and changes in these estimates are recorded when known.

Significant items subject to such estimates include proved reserves and related present value of future net revenues, the carrying value of oil and gas properties, asset retirement obligations, and legal and environmental risks and exposures.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED

Cash and Cash Equivalents

The Company considers all liquid investments with original maturities of three months or less to be cash equivalents. At December 31, 2020 and 2019, the Company did not have any cash equivalents.

Trade Accounts Receivable

Substantially all the Company’s receivables are within the oil and gas industry, primarily from purchasers of oil and gas. Collectability is dependent upon the general economic conditions of the purchasers and the industry. The receivables are not collateralized. The Company has had minimal bad debts; therefore, there is no allowance for doubtful accounts as of December 31, 2020 or 2019. Management considers the following factors when determining the collectability of specific accounts: credit worthiness, past transaction history, current economic industry trends, and changes in payment terms. If the financial condition of the Company’s purchasers were to deteriorate, adversely affecting their ability to make payments, allowances would be necessary.

Oil and Gas Properties

The Company applies the full cost method of accounting for oil and gas properties. Accordingly, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. Those costs include any internal costs that are directly related to development and exploration activities and capitalized interest associated with certain unproved oil and gas properties with ongoing development activities.

Costs associated with proved oil and gas properties are subject to the full cost ceiling limitation which generally limits unamortized capitalized costs to the discounted future net revenues from proved reserves, based on the average of the first day prices and operating cost of the previous twelve months. As a result of the Company’s proved property impairment assessment as of December 31, 2020, the Company recorded a $163.2 million noncash impairment charge to reduce the carrying value of its proved oil and gas properties, which is included in impairments of oil and gas properties in the statements of operations. There were no impairments of proved oil and gas properties for the year ended December 31, 2019.

Costs associated with unproved properties that have not been impaired and costs associated with uncompleted capital projects are excluded from the depletion base. As proved reserves are established, costs associated with unproved properties become part of our depletion base. Costs associated with uncompleted capital projects are included in our depletion base upon completion of the related projects.

Unproved properties are assessed annually to ascertain whether impairment has occurred. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties, become part of our depletion base, and become subject to the full cost ceiling limitation. There were no expired leases during the years ended December 31, 2020 and 2019.

Depreciation, depletion and amortization of proved oil and gas properties are computed on the units–of–production method, using estimates of the underlying proved reserves and costs expected to be incurred to develop our proved undeveloped reserves.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED

Oil and Gas Properties - continued

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.

Prepaid and Other Assets

Prepaid and other assets at December 31 consist of the following:


	2020	2019
Prepaid drilling costs	$19,390	$—
Other	130	97
Total prepaid and other assets	$19,520	$97

Derivative Activity

The Company uses derivative financial instruments to reduce exposure to fluctuations in commodity prices. These transactions are in the form of crude oil and natural gas options and swaps.

The Company reports the fair value of derivatives on the consolidated balance sheet in commodity derivative assets or liabilities as either current or noncurrent determined based on the timing of expected future cash flows of the individual trades. The Company reports these on a gross basis by counter party.

The Company’s derivative instruments were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized along with realized gains and losses in Gain (loss) on derivative instruments, net, in the consolidated statements of operations in the period of change.

Fair Value of Financial Instruments

Certain of our assets and liabilities are measured at fair value as of the reporting period. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. Fair value measurements are classified according to the following hierarchy that consists of three broad levels:

Level 1 inputs: Unadjusted quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 inputs: Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 inputs: Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED

Fair Value of Financial Instruments - continued

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between level 1, level 2, and level 3 of the fair value hierarchy, if applicable, are made at the end of each reporting period.

Loan Origination Costs

Loan origination costs are amortized over the term of the related obligation using the effective interest method. Origination cost associated with our reserves-based line of credit are presented net of amortization within long-term assets. Origination cost associated with our term loan is net of amortization cost and are reported as an offset to the outstanding balance within long-term liabilities.

Equity Method Investment

The Company accounts for its interest in SFS under the equity method of accounting because BPP Acquisition does not have a controlling interest in SFS but has significant influence. BPP Acquisition recognizes it share of earnings and losses in SFS in accordance with its ownership percentage.

Other Accrued Liabilities

Other accrued liabilities at December 31 consist of the following:


	2020	2019
Accrued capital expenditures	$8,010	$5,939
Lease operating expenses payable	3,636	1,481
Interest payable	678	728
Other	5	7
Total other accrued liabilities	$12,329	$8,155

Asset Retirement Obligation

The Company records a liability for asset retirement obligations and increases the carrying value of the related asset in the period in which the liability is incurred. Asset retirement obligations primarily relate to the abandonment of oil and natural gas producing facilities and include costs to dismantle and relocate or dispose of wells and related structures. Accretion expense associated with asset retirement obligations is recorded over time.

The following table shows the changes in the balances of the asset retirement as of December 31 (in thousands).


	2020	2019
Asset retirement obligation, January 1	$523	$152
Liabilities incurred	197	148
Liabilities sold	(8)	—
Changes in estimates	8	193
Accretion expense	43	30
Asset retirement obligation, December 31	$763	$523

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED

Comprehensive income

During the periods ended December 31, 2020 and 2019, the Company did not have any comprehensive income or loss. Accordingly, net income (loss) equals comprehensive income (loss) for the period presented.

Revenue Recognition

The Company’s production is sold through its operated partner who enters into contracts with customers to sell its oil and natural gas production on the Company’s behalf with all related expenses being passed through to the Company. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights.

Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production by the operator and remitted to the Company as a non-operating interest owner. At December 31, 2020 and 2019, the Company had receivables related to contracts with customers of $6.0 million and $14.6 million, respectively.

For non-operated crude oil and natural gas revenues, the Company’s proportionate share of production is generally marketed at the discretion of the operator. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two months after the month in which production occurs.

Oil Contracts - The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. Most of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in transportation and marketing on the Company’s consolidated statements of operations as they represent payment for services performed outside of the contract with the customer.

Natural Gas Contracts - Most of the Company’s natural gas is sold at the lease location or at the outlet of the compressor station owned by SFS, which is generally when control of the natural gas has been transferred to the purchaser. To the extent control of the natural gas transfers upstream of transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified in transportation and marketing on the Company’s consolidated statements of operations.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED

Revenue Recognition - continued

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption allowed for in GAAP. The exemption applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

New Accounting Pronouncements

In February 2016, FASB issued ASU 2016-02 – Leases (Topic 842), which 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 accounting for lease expenses. This update is effective for fiscal years beginning after December 15, 2021, and for interim periods beginning the following year. ASC 842 should be applied using a modified retrospective approach. The Company is in the process of evaluating the impact of this new standard on its financial statements. The new guidance is expected to impact the Company’s balance sheets due to the recognition of right-of-use assets and lease liabilities that are not currently recognized under current accounting standards. The standard does not apply to leases to explore for or use minerals, oil or gas resources.

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" ("ASU 2016-13"). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, 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, 2022, including interim periods within those fiscal years, with early adoption permitted. Entities will use the modified retrospective approach to apply the standard's provisions and record a cumulative-effect adjustment to retained earnings for additional receivable loss allowances, if any, as of the beginning of the first reporting period in which the guidance is adopted. The Company is in the process of evaluating whether it will have a material impact on its consolidated financial statements.

NOTE 3. PROPERTY

Property consisted of the following at December 31 (in thousands):


	2020	2019
Oil and gas properties:
Proved oil and gas properties	$305,091	$263,283
Unproved oil and gas properties excluded from amortization	—	5,681
Accumulated depreciation, depletion and amortization and impairment	(217,708)	(25,867)
Total net oil and gas properties	$87,383	$243,097

Supplemental Property Information:
Depletion expense	$28,618	$20,585
Capitalized interest	$—	$569

NOTE 4. INVESTMENT IN SARAGOSA FIELD SERVICES

On July 11, 2018, the Company completed the purchase of 22% of SFS from Primexx Resource Development, LLC (“PRD”), a wholly owned subsidiary of Primexx Energy Partners Ltd (“PEP”) an affiliated entity (see Note 8), with an effective date of January 1, 2018. The purchase was completed for an initial purchase price of $17.8 million. An additional $6.6 million was contributed through year-end to fund additional infrastructure expansion for a total investment of $24.4 million. The Company has the option to purchase additional interest in SFS not to exceed its pro rata portion acreage held when considering the combined acreage of both PRD and BPP up to 30%.

On April 2, 2019, SFS closed on the sale of certain oil gathering assets to Oryx for a net gain of $31.5 million on May 22, 2019. Primexx Operating Corporation (“POC”), a wholly owned subsidiary of PEP and the operator of the oil and gas assets, will remain the primary customer of the gathering system and, due to this continued involvement, the gain on this transaction is deferred as a liability and amortized over the life of the gathering agreement as other income.

On May 1 and July 2, 2019, the Company completed an additional purchase of 6.23% and 1.75%, respectively, of SFS from PRD to bring its total ownership to 30%. The additional purchased amount was completed for a combined purchase price of $8.7 million.

On December 16, 2019, SFS closed on the sale of its saltwater disposal handling assets to WaterBridge Texas Midstream, LLC (“WaterBridge”) for a total price of $185 million in cash at the time of closing with additional incentives of up to $40 million over the subsequent four-year period based on annual water volumes produced by POC operated wells under a Water Management Services Agreement (“WMSA”). The agreement also gives WaterBridge the first right of refusal to purchase SFS’s water recycling facilities at a future time. Simultaneous with closing this sale, POC entered into a WMSA with a term of twenty years for POC’s operating area. Upon the closing of this transaction, a distribution of $173.7 million was made to BPP and PRD based on their respective ownership.

On September 9, 2020, SFS exercised its option to complete the purchase of an office building and land in Pecos, Texas (the “Pecos Property”) from the Chairman of the Board of Directors (a common unit holder and previously the Company’s Chief Executive Officer) for a total payment of $2.1 million. Prior to the purchase, POC had a lease in place with the owner and utilized the office for field operations. Given the related party nature of the transaction, there is no adjustment to the basis of the Pecos Property and the excess cash paid over the book value is recorded as a reduction in the equity of SFS.

NOTE 4. INVESTMENT IN SARAGOSA FIELD SERVICES - CONTINUED

SFS is accounted for on the equity method basis of accounting. The following details the condensed financial statements as of and for the year December 31, 2020 and 2019 (in thousands):


Condensed Balance Sheet
	2020	2019
Current assets	$7,290	$11,681
Property, plant and equipment, net	89,996	94,667
Total assets	$97,286	$106,348

Current liabilities	4,990	8,855
Total liabilities	29,490	36,016
Members’ equity	67,796	70,332
Total Liabilities and Members’ Equity	$97,286	$106,348

Condensed Income Statement
	2020	2019
Sales	$25,827	$72,855

Cost of sales	2,371	4,735
Field service expense	10,926	24,841
Production taxes	198	202
Depreciation, depletion and amortization	16,351	19,972
General and administrative	643	1,208
Total operating expenses	30,489	50,958

Gain on sale of saltwater disposal system	—	136,342
Other income	2,829	1,891

Net (loss) income	(1,833)	160,130
Net (loss) income attributable to BPP	(550)	47,942
Net (loss) income attributable to controlling owner	($1,283)	$112,188

NOTE 5. DERIVATIVE INSTRUMENTS

The Company engages in price risk management activities. These activities are intended to manage the Company’s exposure to fluctuations in commodity prices for crude oil and natural gas. The Company utilizes financial commodity derivative instruments, primarily price swaps and options.

Commodity derivatives are classified as Level 2 within the fair value hierarchy. The fair value of these instruments is estimated using forward-looking price curves and discounted cash flows that are observable or that can be corroborated by observable market data.

Crude oil derivatives settle against the average of the prompt month NYMEX future prices for West Texas Intermediate.

NOTE 5. DERIVATIVE INSTRUMENTS - CONTINUED

The fair values of commodity derivatives at December 31 were as follows (in thousands):


	2020	2019
Commodity derivative assets
Current portion	$6,060	$236
Long-term portion	2,809	153
	8,869	389

Commodity derivative liabilities
Current portion	76	2,623
Long-term portion	1,868	1,165
	1,944	3,788

Net commodity derivatives	$6,925	($3,399)

The following presents the results of the Company’s oil and gas derivative activity included in revenue in the statements of operations during the periods ended December 31, 2020 and 2019:


	2020	2019
Realized gain (loss)
Oil derivatives	$23,955	($28)
Natural gas derivatives	—	—
Total realized gain (loss)	$23,955	($28)

Unrealized gain (loss)
Oil derivatives	$10,106	($4,644)
Natural gas derivatives	218	—
Total unrealized gain (loss)	$10,324	($4,644)

Gain (loss) on derivative instruments, net	$34,279	($4,672)

NOTE 5. DERIVATIVE INSTRUMENTS - CONTINUED

The Company had the following outstanding open crude oil positions as of December 31, 2020:


	Expirations
	2021		2022	2023
Oil Swaps:
Notional volume (bbl)	1,042,700		279,300	—
Weighted average swap price	$53.54	$53.44	$51.06	$—

Oil Collars:
Notional volume (bbl)	—		30,900	216,200
Weighted average put purchased	$—		$40.00	$40.00
Weighted average call sold	$—		$45.15	$48.36

Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)	1,042,700		279,300	117,700
Weighted average swap price	$1.00		$1.00	$0.30

Natural Gas Swaps:
Notional volume (MMBTU)	858,200		702,600	151,800
Weighted average swap price	$3.06		$2.49	$2.59

Waha Differential (Basis) Swap:
Notional volume (MMBTU)	954,300		702,600	151,800
Weighted average swap price	($0.27)		($0.30)	($0.31)

The Company had the following outstanding open crude oil positions as of December 31, 2019:


	Expirations
	2020		2021	2022
Oil Swaps:
Notional volume (bbl)	1,162,000		794,000	264,000
Weighted average swap price	$57.00	$53.44	$53.54	$51.17

Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)	1,162,000		794,000	264,000
Weighted average swap price	$0.42		$0.99	$1.00

NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES

Debt as of December 31, 2020 and 2019 (in thousands):


	2020	2019
Reserves-based line of credit	$—	$—
Term loan - HPS	75,000	75,000
Deferred loan cost - HPS, net	(1,463)	(1,833)
Total debt outstanding	$73,537	$73,167

NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES - CONTINUED

Reserves-based Lines of Credit

On November 29, 2018, the Company entered into a senior, first lien credit agreement with J.P. Morgan expiring November 28, 2023. Substantially all of the Company’s oil and gas assets are pledged as collateral to be considered as a part of the borrowing base which is set by J.P. Morgan as administrative agent and is redetermined semi-annually. In addition, we may request a borrowing base redetermination up to two times per year based on certain factors. As of December 31, 2020, the borrowing base is $60 million.

The Credit Facility contains certain financial covenants that must be met by BPP. A current ratio of 1.0 times or greater must be maintained at each quarter end. The calculation of the current ratio under the Credit Agreement dictates that the available, undrawn balance on the Credit Facility be added to current assets for debt compliance calculation purposes among other adjustments. Further, the secured debt to EBITDA ratio for the trailing four-fiscal quarters must be no greater than 3.5 times. The covenants also include certain customary restrictions on sales or encumbrances of assets, other advances, indebtedness, distributions and mergers or consolidations.

The applicable base rate is equal to the London Interbank Offered Rate (“LIBOR”) plus a margin ranging from 3% t o 4% based on the percentage of the borrowing base utilized. The Credit Facility carries a commitment fee of 50 basis points on the unused portion of the borrowing base.

Deferred loan cost of $0.2 million and $0.2 million (net of $0.1 million and $0.1 million in amortization) is recorded in long-term assets for the period ended December 31, 2020 and 2019, respectively.

Term Loan Agreement

On December 10, 2018, the Company entered into a $75 million delayed draw term loan with HPS Investment Partners (“HPS”). An amount of $25 million was funded (less discounts on issuance and related bank fees) upon closing with the remaining balance to be drawn within twelve months of the closing date with a maturity of December 10, 2024.

The remaining amount of $50 million was drawn during 2019.

Interest on this term loan is payable quarterly and is at a rate equal to the LIBOR plus 8.0%.

The term loan agreement contains various covenants pertaining to the financial condition of the Company. The covenants include an Asset Coverage Ratio with respect to the relationship between total debt and proved reserves of no less than 1.50 times. For purposes of this covenant, total debt is the debt at BPP EF of $75 million plus any outstanding amounts drawn on the revolving credit facility. The covenants also include certain restrictions on sales or encumbrances of assets, other advances, indebtedness, distributions and mergers or consolidations.

As part of this credit facility, the Company created BPP EF as a subsidiary of BPP.

Deferred loan cost of $1.5 million and $1.8 million (net of $0.7 million and $0.3 million in amortization) as of December 31, 2020 and 2019, respectively. These amounts are presented as an offset to long-term debt.

NOTE 7. MEMBERS’ INTEREST

The Company has two classes of Member Interest consisting of Common Interest and Profits Interest. These interests include the Series A Profits Interest, and two series of Common Interest, the Series B Common Interest and Series C Common Interest. Series A Profits Interest were issued to legacy unit holders of PEP. Additionally, A Profits Interest have been authorized for issuance to management of the Company as incentive compensation. The following chart details the issuance of these units:


Units outstanding as of January 1, 2019			500
Units granted during 2019			60
Forfeitures			—
Units outstanding as of December 31, 2019			560
Units granted during 2020			61
Forfeitures			—
Units outstanding as of December 31, 2020			621

Series A Profits Interest represent equity interest in the Company and its holders participate in profits of the Company once certain payout thresholds are met for the Series B and C Common Interest holders. Accordingly, the value of the Series A Profits Interest at issuance was de minimis.

The Company’s distribution of profit and loss will be applied as follows:

•First, to the Common Interest Holders based on their pro-rata invested capital until all invested capital is recovered and a cumulative amount of distributions are received to achieve a 13.5% rate of return.

•Second, the vested Series A Profits Interest will receive 12.5% of the distributions with the remainder going to Common Interest Holders until the Common Interest Holders achieve a 20% rate of return and a multiple of 2.05 times their invested capital.

•Third, the vested Series A Profits Interest will receive 22.5% of the distributions with the remainder going to the Common Interest Holders until the Common Interest Holders achieve a 30% rate of return and a multiple of 3.05 times their invested capital.

•Lastly, the vested Series A Profits Interest will receive 32.5% of the distributions with the remainder going to the Common Interest Holders.

NOTE 8. MID-TERM INCENTIVE PLAN

In 2020, the Board of Directors established the Mid Term Incentive Plan (“MTIP”) as an incentive program for the Company’s directors, executives, and key employees. The program designates a pool of up to $15.0 million to be granted to employees and provide a cash award when the affiliated Primexx entities (Primexx Energy Partners, Ltd., BPP Energy Partners LLC, and Rock Ridge Royalty Company LLC) have a Liquidity Event. The award is to be split proportionately amongst the affiliated entities based on the cash amount received for each entity. The award vests in two tranches with 65% of the award vesting over a three-year period and 35% of the award is based on personal performance of the grantee as determined by the Board of Directors. The portion that is time vested will fully accelerate and vest upon the change of control of the entities subject to the grantee’s continuous service and remaining in good standing with the Company through the date of the change in control.

Because the MTIP award is not considered a substantive class of equity, and only pays grantees upon a liquidity event of the entity, there is no expense recorded in the financial statements related to these awards. As of December 31, 2020, the total pool granted to employees under the MTIP was completely distributed.

NOTE 9. RELATED PARTY TRANSACTIONS

Primexx Energy Partners Ltd.

The Company has shareholders and management in common with PEP. In connection with the formation of the Company, the board approved a shared service agreement between the two companies so that all operations of the Company are conducted by a subsidiary of PEP and the cost of shared resources (including technology, office space and personnel) are reimbursed to PEP by the Company at a rate of cost plus 2%. Additionally, the Company holds non-operated working interest in wells currently being drilled by PEP. Accordingly, PEP is responsible for distributing the Company’s share of revenue and invoicing for the related share of capital and lease operating expenses in accordance with the ownership held by the Company.

SFS, an equity method investment of BPP, is a controlled subsidiary of PEP that owns the company’s field services assets in Reeves County, which include gas gathering, water management, and other oil field service assets. See Note 4 for additional information.

The following amounts were transacted between BPP and PEP (in thousands):


	2020	2019
Affiliate payable to PEP	$1,610	$9,906
Revenue paid from PEP	$50,240	$41,723
Capital and lease operating expenses paid via joint interest billings to PEP	$43,241	$115,845
General and administrative expenses reimbursed	$4,172	$3,239

BPP had $19.4 million and $0 of unapplied prepaid capital expenditures deposited with PRD recorded in current prepaid assets as of December 31, 2020 and 2019, respectively.

During the year ended December 31, 2019, the Company sold a lease for 203 acres in the amount of $2.0 million (the Company’s cost basis) to PEP.

Rock Ridge Royalty Company

The Company has shareholders and management in common with Rock Ridge Royalty Company (“RRR”) a Delaware limited liability company formed in 2016 to acquire and hold mineral and royalty interests in the Delaware Basin. During 2019, the Company leased approximately 360 acres to BPP receiving a total lease bonus of $3.8 million, respectively.

NOTE 10. COMMITMENTS AND CONTINGENCIES

The Company’s operations are subject to all the operational and environmental risks normally associated with the crude oil and natural gas industry. Additionally, the Company may become involved from time to time in litigation on various matters which are routine to the conduct of its business. Management is not currently a party to any material litigation and is not aware of any litigation threatened against the Company that could have a material adverse effect on the Company.

NOTE 10. COMMITMENTS AND CONTINGENCIES - CONTINUED

Current economic conditions may adversely affect the results of operations in future periods. The novel coronavirus (“COVID-19”) pandemic significantly affected the global economy and created significant volatility in the financial markets. These events, in addition to disruptions in the demand for oil combined with pressures on the global supply-demand balance for oil, resulted in significant volatility in oil prices during 2020. The effects of the COVID-19 pandemic negatively impacted the Company’s results of operations and led to a reduction in capital activities. The impact of these events on the financial performance of the Company’s long-term operations is uncertain, including the duration of the COVID-19 pandemic and long-term effects on global oil demand. The financial statements have been prepared using values and information currently available to the Company.

NOTE 11. SUBSEQUENT EVENTS

On January 8, 2021, the Company and PRD entered into an agreement with a third party to contribute oil and gas leases and certain properties to a joint development area comprising 960 gross acres effective February 26, 2021. At closing, the Company received total consideration of $0.9 million in exchange for interests in certain properties and future technical consulting services in the joint development area.

Subsequent events have been evaluated through March 31, 2021, the date on which the financial statements were available to be issued.

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Geographic Area of Operation

The Company’s oil and natural gas reserves are located within the continental United States and concentrated in the Delaware Basin of Texas.

Capitalized Oil and Natural Gas Costs

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


	December 31, 2020	December 31, 2019
Oil and gas properties
Proved oil and gas properties	$305,091	$263,283
Unproved oil and gas properties	—	5,681
Accumulated depletion and impairment	(217,708)	(25,867)
Net oil and gas properties capitalized	$87,383	$243,097

Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows (in thousands):


	December 31, 2020	December 31, 2019
Acquisition costs
Proved oil and gas properties	$14	$1
Unproved oil and gas properties	1,679	13,680
Development costs	34,376	102,178
Exploration costs	—	225
Total costs incurred	$36,069	$116,084

Results of Operations from Oil and Natural Gas Producing Activities

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


	December 31, 2020	December 31, 2019

Oil and natural gas sales	$43,672	$55,613
Production costs	(16,168)	(16,538)
Depletion	(28,618)	(20,585)
Impairment of oil and gas properties	(163,223)	—
Results of operations from oil and natural gas producing activities	($164,337)	$18,490

The reserves as of December 31, 2020 and 2019 presented below were prepared by independent petroleum engineers. The calculation and analysis of interim changes in proved reserves were prepared by the Company. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in the Delaware Basin of Texas.

The following tables set forth estimated net quantities of the Company’s estimated proved reserves, projected future cash inflows, and future production and development costs and are prepared in accordance with guidelines established by the SEC. Accordingly, the reserve estimates are based upon existing economic and operating conditions. For estimates of proved reserves, the average spot prices are determined based upon the 12-month unweighted average of the first day of the month prices adjusted by applying price and cost basis differentials,

including transportation and quality, and are then applied to the period-end estimated quantities of oil, natural gas and natural gas liquids (“NGL”) to be produced in the future. Future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by GAAP. These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Analysis of Changes in Proved Reserves

The following table sets forth information regarding the Company’s net ownership interest in estimated quantities of proved developed and undeveloped oil and natural gas quantities and the changes therein for each of the periods presented:


	Oil	Natural Gas	NGLs	Total
	(MBbls)	(MMcf)	(MBbls)	(MBOE)
Balance, January 1, 2019	13,389	14,106	3,242	18,982
Revisions	(1,684)	2,032	(372)	(1,717)
Extensions	12,098	15,299	2,720	17,368
Acquisitions of reserves	142	404	71	280
Production	(1,014)	(1,080)	(190)	(1,384)
Balance, December 31, 2019	22,931	30,761	5,471	33,529
Revisions	(9,883)	(9,947)	(1,688)	(13,230)
Extensions	5,979	10,416	1,875	9,591
Acquisitions of reserves	60	135	25	108
Production	(1,154)	(1,839)	(330)	(1,791)
Balance, December 31, 2020	17,933	29,526	5,353	28,207


	Oil	Natural Gas	NGLs	Total
Proved developed and undeveloped reserves:	(MBbls)	(MMcf)	(MBbls)	(MBOE)
Developed as of December 31, 2018	2,077	2,315	555	3,018
Undeveloped as of December 31, 2018	11,312	11,791	2,687	15,964
Balance at December 31, 2018	13,389	14,106	3,242	18,982

Developed as of December 31, 2019	5,411	8,060	1,392	8,146
Undeveloped as of December 31, 2019	17,520	22,701	4,079	25,383
Balance at December 31, 2019	22,931	30,761	5,471	33,529

Developed as of December 31, 2020	3,630	6,734	1,225	5,977
Undeveloped as of December 31, 2020	14,303	22,792	4,128	22,230
Balance at December 31, 2020	17,933	29,526	5,353	28,207

Revisions to previous estimates of proved reserves, either upward or downward, are a result of updated information obtained in the reporting period, including operator drilling activity and production history or changes in economic factors such as commodity prices, operating and development costs.

During the year ended December 31, 2020, the Company’s extensions and discoveries of 9,591 MBOE resulted primarily from conversions of non-proved and contingent resources to proved due to drilling activity. The Company acquired 108 MBOE in Reeves County, Texas from 0.1 net producing wells and 0.1 net undeveloped locations. In addition, the Company negatively revised previous estimates by 13,230 MBOE due to the following:

•Downgrade of 10,701 MBOE of proved reserves to non-proved due to the decrease in drilling activity in 2020 resulting in development moving outside of the five-year development window,

•Negative revision of 3,326 MBOE due to downward movement in SEC pricing,

•Increase of 792 MBOE due to decreases in gas and NGL processing and basis differentials, and

•Positive revision of 5 MBOE attributed to upward revisions of estimated ultimate recovery, changes in operating and development costs, and adjustments to well spacing and development timing.

During the year ended December 31, 2019, the Company’s extensions and discoveries of 17,368 MBOE resulted primarily from conversions of non-proved and contingent resources to proved due to drilling activity. The Company acquired 280 MBOE in Reeves County, Texas from 0.5 net producing wells. In addition, the Company negatively revised previous estimates by 1,717 MBOE due to the following:

•Negative revision of 4,008 MBOE due to downward movement in SEC pricing,

•Decrease of 48 MBOE due to increases in gas and natural gas liquids processing and basis differentials, and

•Positive revision of 2,339 MBOE attributed upward revisions of estimated ultimate recovery, changes in operating and development costs, and adjustments to well spacing and development timing.

Standardized Measure of Oil and Gas

The standardized measure and projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Our calculations of the standardized measure of discounted future net cash flows and the related changes therein do not include the effect of estimated federal income tax expenses because the Company is not subject to federal income taxes. The Company is subject to certain state-based taxes; however, these amounts are not material.

As of December 31, 2020, the reserves are comprised of 64% crude oil, 17% natural gas and 19% NGL on an energy equivalent basis.

The values for the December 31, 2020 and 2019 proved reserves were derived based on prices presented in the table below. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the NGL pricing was 21% of WTI for 2020 and 33% of WTI for 2019; the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.


	Oil	Natural Gas	NGLs
	($/Bbl)	($/Mcf)	($/Bbl)
December 31, 2020 (Average)	36.62	0.130	8.32
December 31, 2019 (Average)	46.10	-0.021	18.32

The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):


	December 31, 2020	December 31, 2019

Future oil and natural gas sales	$705,019	$1,156,636
Future production costs	(317,487)	(390,967)
Future development costs	(203,563)	(261,002)
Future net cash flows	183,969	504,667
10% annual discount	(96,586)	(251,002)
Standardized measure of discounted future net cash flows	$87,383	$253,665

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):


	Year Ended December 31,
	2020	2019

Standardized measure, beginning of year	$253,665	$167,641
Net change in prices and production costs	(68,124)	57,424
Changes in future development costs	131,911	54,944
Oil and gas sales, net of production costs	(27,504)	(39,075)
Extensions and discoveries	33,182	150,177
Acquisitions of reserves	340	3,407
Revisions of previous quantity estimates	(127,191)	(28,861)
Development costs incurred during the period	8,564	29,762
Accretion of discount	25,367	16,764
Changes in timing and other	(142,827)	(158,518)
Standardized measure, end of year	$87,383	$253,665