Pioneer PE Holding LLC - FORM 8-K - EX-99.1

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EX-99.2 - EX-99.2 - Pioneer PE Holding LLC	d268232dex992.htm
8-K - 8-K - Pioneer PE Holding LLC	d268232d8k.htm

Exhibit 99.1

LOGO

Consolidated Financial Statements

(Unaudited)

For the Quarterly Period ended

March 31, 2017

DOUBLE EAGLE ENERGY PERMIAN LLC

INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS


	Page
Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016		3

Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016		4

Consolidated Statements of Changes in Members’ Equity for the Three Months Ended March 31, 2017 and 2016		5

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016		6

Notes to Consolidated Financial Statements		7

Double Eagle Energy Permian LLC

Consolidated Balance Sheets


	As of March 31,
	2017			As of December 31,
	(Unaudited)			2016
Assets
Current assets:
Cash	$	4,219,596		$	90,563,549
Restricted cash		—			7,997,500
Accounts receivable		14,022,336			9,630,810
Advances to operators		10,036,982			10,538,492
Other assets		229,225			347,809

Total current assets		28,508,139			119,078,160
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Proved properties		233,155,877			207,716,984
Unproved properties		764,458,079			632,325,983
Other equipment		424,792			249,676

Total oil and gas properties		998,038,748			840,292,643
Less: Accumulated depreciation, depletion and amortization		(21,857,417	)		(17,533,065	)

Total oil and gas properties, net		976,181,331			822,759,578
Deferred financing fees, net		3,849,797			4,021,216

Total assets	$	1,008,539,267		$	945,858,954

Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	8,482,622		$	5,089,632
Accrued oil and gas development expenditures		16,838,294			14,176,549
Derivative liability		1,264,480			2,744,107

Total current liabilities		26,585,396			22,010,288
Long-term derivative liability		3,371,124			1,533,254
Texas margin tax		2,689,004			2,564,734
Deferred lease acquisition costs		185,000			370,000
Long-term debt		50,000,000			—
Asset retirement obligations		5,796,900			3,956,491
Members’ Equity		919,911,843			910,407,507
Non-controlling interest		—			5,016,680

Total liabilities and members’ equity	$	1,008,539,267		$	945,858,954

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

Double Eagle Energy Permian LLC

Consolidated Statements of Operations

(Unaudited)


	For the Three Months Ended March 31,
	2017			2016
Revenues:
Oil, natural gas and natural gas liquids sales	$	14,161,775		$	5,613,518
Other		58,933			9,414

Total revenue	$	14,220,708		$	5,622,932

Operating Expenses:
Lease operating expenses		2,137,536			2,011,120
Production and ad valorem taxes		820,247			388,394
Transportation and processing		525,520			308,924
Abandonments of oil and gas properties		613,916			224,999
General and administrative		9,627,048			1,648,285
Depreciation, depletion and amortization		4,380,125			2,212,284
Gain on sale of oil and gas properties		(3,282	)		(83,090	)

Total costs and expenses		18,101,110			6,710,916

Operating loss		(3,880,402	)		(1,087,984	)
Other income (expense):
Interest, net		(363,239	)		(186,000	)
Loss on unrealized oil and gas hedges		(358,243	)		—
Gain on realized oil and gas hedges		291,771			—

Loss before income taxes		(4,310,113	)		(1,273,984	)
Texas margin tax		124,270			80,801

Net loss	$	(4,434,383	)	$	(1,354,785	)

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

Double Eagle Energy Permian LLC

Consolidated Statements of Changes in Members’ Equity

(Unaudited)


	Members’ Equity			Non-controlling Interest			Total
Balance - December 31, 2016	$	910,407,507		$	5,016,680		$	915,424,187
Net loss		(4,434,383	)		—			(4,434,383	)
Capital contributions		22,829,577			61,765			22,891,342
Equity based compensation		68,750			—			68,750
Purchase of Non-controlling interest		(9,498,273	)		(5,078,445	)		(14,576,718	)
Parent company net investment		538,665			—			538,665

Balance - March 31, 2017	$	919,911,843		$	—		$	919,911,843

Balance - December 31, 2015	$	228,617,939		$	—		$	228,617,939
Net loss		(1,354,785	)		—			(1,354,785	)
Capital contributions		60,328,762			—			60,328,762
Capital distributions		(7,188,106	)		—			(7,188,106	)
Parent company net investment		9,089,824			—			9,089,824

Balance - March 31, 2016	$	289,493,634		$	—		$	289,493,634

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

Double Eagle Energy Permian LLC

Consolidated Statements of Cash Flows

(Unaudited)


	For the Three Months Ended
	March 31, 2017			March 31, 2016
Cash flows provided by (used in) operating activities:
Net loss	$	(4,434,383	)	$	(1,354,785	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		4,380,125			2,212,284
Amortization of deferred financing costs		171,418			14,281
Texas margin tax expense		124,270			80,801
Abandonment of oil and gas properties		613,916			224,999
Equity-based compensation		68,750			—
Gain on sale of oil and gas properties		(3,282	)		(83,090	)
Derivative loss		358,243			—
Changes in operating assets and liabilities:
Accounts receivable		(4,391,526	)		(459,209	)
Other assets		118,584			—
Accounts payable and accrued liabilities		3,392,991			(1,671,750	)
Accounts payable to related parties		—			(1,977,282	)

Net cash provided by (used in) operating activities	$	399,106		$	(3,013,751	)

Cash flows from investing activities:
Purchase of oil and gas properties and development expenditures	$	(145,935,498	)	$	(63,631,811	)
Purchase of Non-controlling interest		(14,576,717	)		—
Proceeds from sale of oil and gas properties		12,755			322,500
Advances to operators		501,510			(988,942	)
Purchase of other property and equipment		(175,115	)		—

Net cash used in investing activities	$	(160,173,065	)	$	(64,298,253	)

Cash flows from financing activities:
Borrowings under long-term debt	$	50,000,000		$	15,758,000
Principal payments on long-term debt		—			(10,530,000	)
Capital contributions		22,891,341			60,503,762
Capital distributions		—			(7,188,106	)
Payment for deferred financing costs		—			(113,313	)
Parent company net investment		538,665			9,089,826

Net cash provided by financing activities	$	73,430,006		$	67,520,169

Net increase (decrease) in cash	$	(86,343,953	)	$	208,165
Cash - Beginning of period	$	90,563,549		$	—

Cash - End of period	$	4,219,596		$	208,165

Non-cash transactions:
Use of restricted cash for purchase of oil and gas properties	$	7,997,500		$	—

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

Double Eagle Energy Permian LLC

Notes to the Consolidated Financial Statements

(Unaudited)

1.	ORGANIZATION AND NATURE OF BUSINESS

Description of the business and formation

Double Eagle Energy Permian LLC’s (the “Company,”, “DEEP,” “we,” “our,” “us”), a Delaware limited liability company, was formed on September 29, 2016 (“date of inception”). The Company’s principal business is crude oil and natural gas exploration, development and production with operations in the Midland Basin of West Texas in the United States. We are an independent energy company engaged in the acquisition, exploration, development and production of crude oil and natural gas properties.

On September 29, 2016, the Company was formed by contributions from Double Eagle Energy Holdco LLC (“DEEH”), a newly formed parent of Double Eagle Energy Operating II LLC (the “Parent”, “Double Eagle”, “DE”), of its wholly-owned subsidiary, Double Eagle Lone Star LLC (“Lone Star”) and a third party, Veritas Energy Partners Holdings, LLC (“Veritas”), of its wholly owned subsidiary, Veritas Energy Partners, LLC (“Veritas Sub”). DEEH and DE are also wholly owned subsidiaries of Double Eagle Energy Holdings II LLC, (“DEEH II”) where all the board decisions and assets relating to Lone Star were historically managed.

Following the contribution of assets, DEEH held approximately 70% of DEEP’s equity, with Veritas holding the remaining 30%. The transactions between DEEH, DE, Lone Star and DEEH II were treated as a reorganization of entities under common control (as defined by U.S. GAAP), while Veritas’ contribution was treated as an acquisition of Veritas by DEEP. The financial statements included herein and associated notes and operations reflect the change in reporting entity and therefore are presented as if the Company existed and owned the assets since their acquisitions by DE. Lone Star was conveyed and recorded by the Company at DE’s respective historical carrying amounts. Certain amounts recorded and presented at DE that had not previously been allocated to the Company have been allocated to the Company to fairly present the financial results of the Company on a standalone basis. These allocations were performed utilizing systematic methods based on the operations of Lone Star.

On November 7, 2016, DEEP entered into a Unit Subscription Agreement (the “Subscription Agreement”), with another third party equity provider (the “Capital Provider”), to sell units in DEEP, representing approximately 7.5% of DEEP’s equity interests, to the Capital Provider for $150 million. Upon closing of the Subscription Agreement, the equity interests in DEEP held by DEEH, Veritas and the Capital Provider were approximately 64.75%, 27.75% and 7.5%, respectively.

On February 7, 2017, we entered into a contribution agreement (the “Parsley Energy Contribution Agreement”) with Parsley Energy, Inc. (“Parsley”), which provides for the contribution by the Company of certain wholly owned subsidiaries of the Company. As a result, substantially all assets and interests of the Company were acquired for an aggregate purchase price of approximately $2.8 billion, subject to certain purchase price adjustments set forth in the Parsley Energy Contribution Agreement. The aggregate purchase price will consist of (i) approximately $1.4 billion in cash and (ii) approximately 39.4 million units in Parsley LLC (“PE Units”) and approximately 39.4 million corresponding shares of Parsley’s Class B common stock.

Upon the expiration of a 90-day lock-up period following the consummation of the transaction, each PE Unit, together with a corresponding share of PE Class B common stock, will be exchangeable, at the option of the holder, for one share of PE Class A common stock or cash. The Parsley Energy Contribution Agreement contains customary representations and warranties, covenants and indemnification provisions and has an effective date of January 1, 2017. The transaction closed on April 20, 2017.

As of March 31, 2017 and December 31, 2016, the consolidated balance sheets include all specific oil and natural gas assets, current assets, current liabilities and asset retirement obligations of Lone Star, and those assets that were specifically tracked within the entity. In addition to the specific assets of Lone Star, management allocated debt and deferred financing costs related to the debt that had previously been entered into, and accounted for, by the Parent. These allocations were based on a ratio of oil and natural gas assets at Lone Star to the total oil and natural gas assets of the Parent. Management deemed this allocation method appropriate given the capital intensive nature of its business, and the correlation of the capital expenditures to the reserve-based borrowing facility. On September 30, 2016, immediately following the closing of the Veritas Acquisition, and in connection with the Parent’s

redetermination on its existing loan agreement, the Company’s joint and several liability related to the Parent debt was removed. With the removal of the Parent debt, the Company entered into a new reserve-based lending agreement guaranteed by the underlying assets of DEEP. Due to these events, there is no Parent debt allocated to the standalone financials of DEEP as of and for any period subsequent to September 30, 2016. See Note 4, Long Term Debt for further discussion regarding the indebtedness of the Company.

The consolidated statement of operations for the three month period ended March 31, 2016 includes allocations for certain general and administrative expenses, stock-based compensation and interest expense. All other costs and expenses were tracked at the individual asset level, and no allocations were necessary. No revenue was allocated to the Company, from the Parent or otherwise, for the before mentioned period. The allocation method selected by management for these costs was based on the ratio of oil and natural gas assets at Lone Star to the total oil and natural gas properties of the Parent. For the three month period ended March 31, 2016, these expenses were allocated from the Parent based on the oil and natural gas properties held by the Company to total oil and natural gas properties of the Parent at the end of each quarter. The allocation percentage used was 66% for the three month period ended March 31, 2016.

The impacts of the formation of the Company on September 29, 2016 and related allocations to Lone Star from the Parent arising from the reorganization of entities under common control impacts the comparability of the March 31, 2017 consolidated financial statements and the 2016 consolidated financial statements.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation – The accompanying consolidated financial statements and related notes present the consolidated balance sheets as of March 31, 2017 and December 31, 2016, and the consolidated statements of operations, changes in members’ equity and cash flows for the three months ended March 31, 2017 and 2016. Certain transactions between the Company and DEEH, as well as DE, together referred to as the Parent, have been presented in these consolidated financial statements as Parent company contributions as they are considered to be effectively settled at the time each transaction is recorded and there is no expectation of repayment by DEEP. The total net effect of the settlement of these transactions is reflected in the consolidated statements of changes in members’ equity as Parent company net investment, in the consolidated statements of cash flows as a financing activity and in the Company’s consolidated balance sheets in members’ equity. Unless otherwise stated, all amounts contained within the consolidated financial statements and accompanying notes are the responsibility of the Company, either as they were incurred by the Company through normal operations or were allocated to the Company from DE or DEEH.

The accompanying consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). Our consolidated financial statements include the accounts of the Company.

The Company’s consolidated financial statements include allocations of certain assets, liabilities and operating expenses historically held or incurred by the Parent, including equity-based compensation and other general and administrative expenses incurred by the Parent on behalf of its wholly owned subsidiaries, of which the Company is included.

Use of Estimates – The preparation of consolidated financial statements under 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates and judgments are based on information available at the time such estimates and judgments are made. Although management believes the estimates are appropriate, actual results may differ from those estimates.

The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense.

Cash and cash equivalents – As of September 30, 2016, and coinciding with the formation of DEEP and new reserve based lending agreement, the Company was no longer party to the Parent’s central cash management process and as such began carrying its own cash on its consolidated balance sheets. Previously, the Company consolidated treasury functions at the Parent to reduce the number of entities that were able to make payments or receive cash related to the operations of the business. Due to the change, the Company was no longer required to carry its own cash on its consolidated balance sheets. Cash transactions performed by the Parent prior to March 31, 2016, that directly related to the operations and activity of DEEP, have been presented in the consolidated statements of cash flows as if they were transactions of DEEP. Any amounts that will not be cash settled between DEEP and the Parent are treated as contributions and distributions in the accompanying consolidated statements of members’ equity and cash flows and in addition are included in the “Parent company net investment” line.

Cash and cash equivalents that are restricted as to withdrawal or use under the terms of certain contractual agreements are presented as Restricted cash on our consolidated balance sheets. Our restricted cash balance at December 31, 2016 primarily include various escrow agreements related to 1031 tax exchange transactions that were utilized for property acquisitions in 2017.

Accounts Receivable – Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. As the Company has not experienced any credit losses, no allowance for doubtful accounts was recorded as of March 31, 2017 and December 31, 2016.

Advances to Operators – The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the operator of the well may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by the operator against future development costs.

Oil and natural gas properties – The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved developed or total proved reserves, as applicable. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited to the net book value of the amortization group, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

The Company performs assessments of its long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. We consider the inputs utilized in determining the fair value related to the impairment of long-lives assets to be Level 3 measurements in the fair value hierarchy. Since inception, the Company has not realized any impairments of its proved properties.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time. For the three months ended March 31, 2017 and 2016, the Company recognized approximately $0.6 million and $0.2 million, respectively, related to lease expirations on its unproved properties, which are included in abandonments of oil and gas properties on the consolidated statements of operations.

The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. For the three months ended March 31, 2017 and March 31, 2016, the Company has not capitalized any interest as projects generally lasted less than six months.

Asset Retirement Obligations – Asset retirement obligations relate to future costs associated with the plugging and abandonment of crude oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition. Estimates are based on estimated remaining lives of those wells based on reserve estimates, external estimates to plug and abandon the wells in the future, inflation, credit adjusted discount rates and federal and state regulatory requirements. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Accretion expense is included in “Depreciation, depletion and amortization” on our consolidated statements of operations.

The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

Deferred Financing Costs – Deferred financing costs include origination, legal and other fees to obtain or issue debt. These costs are deferred and reported on the consolidated balance sheets at cost, net of amortization. As the Company’s debt agreement is limited to lines of credit, total deferred financing costs are amortized on a straight line basis, which approximates the effective interest method, to interest expense over the term of the associated debt.

Revenue Recognition – The Company recognizes crude oil (“oil”), natural gas and natural gas liquids (“NGLs”), cited collectively throughout the accompanying notes as oil and natural gas, revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of March 31, 2017 and December 31, 2016, the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest was materially consistent with its entitled interests in natural gas production from wells.

Concentrations of Credit Risk – As of March 31, 2017 and December 31, 2016, the Company’s primary market consists of operations in the Midland Basin of West Texas in the United States. The Company has concentration of oil and natural gas production revenues and receivables due from the operators of wells in which we hold non-operated working interests. Our exposure to non-payment or non-performance by the operators, our customers and counterparties presents a credit risk. Generally, non-payment or nonperformance results from a customer’s or counterparty’s inability to satisfy obligations. We monitor the creditworthiness of our customers and counterparties and established credit limits according to our credit policies and guidelines, but cannot assure that any losses will be consistent with our expectations.

Furthermore, the concentration of our counterparties in the energy industry may impact our overall exposure to credit risk as customers may be similarly affected by prolonged changes in economic and industry conditions. The Company actively invests in non-operated wells with financially stable and experienced operators in the respective areas of exploration, development and production. Although the Company is exposed to a concentration of credit risk, management believes the loss of revenue from any one customer would not significantly affect the Company’s financial or operational performance.

Equity-Based Compensation – Equity-based compensation expense is recognized on Series B Units of the Company that are expected to participate in future profits of the Company upon a liquidity event. The fair value of the units on the grant date is recorded to expense as the units vest. The amount of equity-based compensation expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested as of that date. See further discussion regarding the Company’s B Units and equity-based compensation in Note 7, Members’ Equity and Equity-Based Compensation.

Financial Instruments and Hedging – The Company’s financial instruments include cash, advances to operators, accounts receivable, accounts payable and accrued liabilities and are carried at cost, which approximates fair value due to the short-term maturity of these instruments.

The Company enters into derivative and hedging contracts to help reduce the price risk attributable to our expected oil and natural gas production. The Company does not follow hedge accounting for its hedging contracts. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. Changes in a derivative’s fair value are recognized in earnings in the accompanying consolidated statements of operations and cash flows, and derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

Our derivative and hedging contracts are measured at fair value with a market approach using third-party pricing services, which is corroborated with data from active markets or broker quotes. Based on the nature of these inputs, we consider the pricing and quotes received to be Level 2 measurements in the fair value hierarchy.

Fair Value Hierarchy – 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 at the reporting date. The Company’s assets and liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes inputs and assumptions underlying the valuation techniques. This fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs, and consists of three broad levels:

•

Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•

Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

•

Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data. These inputs generally reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

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.

Recently Issued Accounting Standards

Leases. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities in the consolidated balance sheets, and requiring companies to disclose additional information about their leasing arrangements. We expect to adopt the provisions of this standard effective January 1, 2019. The Company is currently evaluating the new guidance and has not determined the impact, if any, this standard may have on our consolidated financial statements.

Revenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Company is currently evaluating the method of adoption as well as the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Income Taxes. In November 2015, FASB issued ASU 2015-17, Income Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities be classified as noncurrent in the consolidated balance sheets. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. The Company is currently evaluating the new guidance and has not determined the impact, if any, this standard may have on our consolidated financial statements.

Financial Instruments—Overall. In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall, which addresses the fair value measurements, impairment assessment and disclosure requirements of equity securities, equity investments and other financial instruments and also clarifies current guidance to aid in the reduction of diversity in practice. For public business entities, the amended guidance is effective for fiscal years beginning after December 15, 2017 and for interim periods within those years. The amended guidance should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments related to equity securities without readily determinable fair values should be applied prospectively. The Company has not yet determined the effect of the standard on its ongoing financial reporting.

Statement of Cash Flows. In August 2016, The FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), which provides guidance on eight specific cash flow issues, including cash payments associated with debt and debt modification, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and corporate-owned life insurance policies, distributions made from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. Early adoption is permitted for any entity in any interim or annual period. The Company is evaluating the ASU and has not determined the effect of the standard on its ongoing financial reporting.

Statement of Cash Flows. In November 2016, The FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), which requires that a statement of cash flows to explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statements of cash flows. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. Early adoption is permitted for any entity in any interim or annual period. The Company is evaluating the ASU and has not determined the effect of the standard on its ongoing financial reporting.

Business Combinations. In January 2017, The FASB issued ASU No. 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a screen to determine when a set is not a business, which requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not considered a business. This reduces the number of transactions that require further evaluation. Further, this ASU provides a framework to assist entities in evaluating whether both an input and a substantive process are present as well as narrows the definition of the term output so that the term is consistent with how outputs are described in Topic 606. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after their effective date and no disclosures are required at transition. Early adoption is for transactions for which the acquisition date or disposal date occurs before the issuance date or effective date of the amendment, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company is evaluating the ASU and has not determined the effect of the standard on its ongoing financial reporting.

3.	ACQUISITIONS

The Company accounts for acquisitions of proved property as business combinations and, accordingly, the results of operations are included in the accompanying consolidated statements of operations from the closing date of the acquisition.

Veritas Energy Partners – On September 29, 2016 to align its business operations with management’s revised strategy to become an operator with a focus on horizontal drilling, the Company acquired Veritas Energy Partners. As part of the agreement, DEEH contributed all of the Lone Star assets to the Company in exchange for Series A units representing an approximate 70% interest in DEEP; Veritas contributed all of the ownership interests of its wholly owned subsidiary to DEEP in exchange for Series A units

representing an approximate 30% interest in DEEP. At closing, the Company recorded the assets and liabilities of Veritas Energy at their respective fair values.

The following table summarizes the fair values of assets acquired and liabilities assumed as of September 29, 2016:


Condensed Balance Sheet of Assets Acquired and Liabilities Assumed
Current assets
Cash and cash equivalents	$	6,777,181
Accounts receivable		2,674,057
Other current assets		154,656

Total current assets		9,605,894
Oil and gas properties
Proved oil and gas properties		38,941,679
Unproved oil and gas properties		277,722,754

Total fair value of oil and gas properties acquired		316,664,433
Liabilities assumed
Accounts payable and accrued liabilities		4,815,078
Asset retirement obligation		686,800

Consideration transferred	$	320,768,449

4.	LONG-TERM DEBT

On September 30, 2016, the Company entered into a Credit Agreement with JPMorgan Chase Bank, N.A. (“Credit Agreement”), as administrative agent (“Administrative Agent”), and a syndicate of lenders, with a maximum revolving credit facility of $500.0 million with an initial borrowing base of $60.0 million (“JPM Revolver”). However, the Company’s ability to draw on the JPM Revolver is limited by an Indenture Agreement between the Company and the Capital Provider, as discussed below, thereby effectively reducing the borrowing base. The JPM Revolver is secured by liens on substantially all of the Company’s properties and guarantees from the Company’s subsidiaries. The Credit Agreement of the JPM Revolver contains restrictive covenants that may limit our ability to, among other things, issue or incur additional indebtedness, enter into mergers, make investments or enter into hedging contracts.

The amount available to be borrowed is subject to the borrowing base that is redetermined semi-annually each May and November, with such redetermination effective May 1 and November 1, respectively, or as redetermined between those dates as requested by the Company and allowed under the Credit Agreement. The amount of the borrowing base depends on the volumes of our proved oil and natural gas reserves and estimated cash flows from these reserves and other information deemed relevant by the Administrative Agent. As of March 31, 2017 and December 31, 2016, the effective borrowing base of the JPM Revolver was $85 million and $65 million, of which $50 million was drawn as of March 31, 2017 and none was drawn as of December 31, 2016. See further discussion below related to the limitations on borrowing by the Capital Provider Indenture Agreement.

Upon execution of the Credit Agreement, we were required to provide evidence satisfactory to the Administrative Agent that we had entered into hedge agreements, as defined, covering at least 50% of reasonably anticipated production for each month. During the period which the Credit Agreement is in effect, hedged volumes may not exceed 85% of the reasonably anticipated production (based on forecasts from reserve reports acceptable to the Administrative Agent) for any 66 month period from the creation of the most recent Hedging Agreement. The Credit Agreement also specifies the hedge agreements may not be entered into for speculative purposes – see Note 6, Derivatives and Hedging.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for any borrowings under an alternate base rate loan (“ABR Loans”) and at the end of the applicable interest period for LIBOR-based loans (“LIBOR Loans”). We have an option to borrow under LIBOR-based or ABR type Loans. LIBOR Loans bear interest at a base LIBOR rate specified in the agreement, plus an applicable margin which ranges from 250 to 350 basis points based on the percentage of borrowing base utilized. ABR Loans bear interest at a base rate, established by the Administrative Agent plus an applicable margin ranging from 150 to 250 basis points based on the percentage of borrowing base utilized.

On September 30, 2016, the JPM Revolver replaced a previous debt instrument entered into by the Parent, on behalf of its subsidiaries. On February 2, 2015, the Parent entered into a credit agreement, partially secured by the assets of the Company, with

Wells Fargo Bank, N.A. (“RBL Loan”). The debt instrument, a Reserves Based Loan (“RBL”), provides for revolving credit loans to be made and letters of credit to be issued from time to time for the account of the Parent. The aggregate amount of the commitment from Wells Fargo and banks in the syndicate is $250.0 million.

As the credit facility was partially secured by the assets of the Company, DEEP previously had a financial obligation to repay the Parent for any borrowings made on its behalf, requiring an allocation of the borrowing base and outstanding borrowings. Obligations under the RBL were secured by a first-priority security interest in substantially all of the Parent’s proved reserves. In addition, obligations under the RBL were guaranteed by the Parent’s operating subsidiaries, of which the Company is listed. The balance of the RBL Loan associated to DEEP was transferred in full to the Parent during September 2016, at which time the RBL Loan agreement pertaining to DEEP was terminated.

As of September 30, 2016, the Parent’s deferred financing fees that had been allocated to the Company were written off as the Company’s joint and several liability related to the Parent debt was removed and the Company entered into a new credit facility, as noted above. The amounts included in deferred financing fees as of March 31, 2017 and December 31, 2016 in the accompanying consolidate balance sheets include amounts related to the Company’s new credit facility and additional debt raise, noted below.

In addition to the Company’s equity offering to the Capital Provider (see Note 7, Members Equity and Equity-based Compensation) on November 7, 2016 DEEP and the Capital Provider also entered into a Senior Notes Purchase Agreement whereby DEEP may issue and sell to the Capital Provider up to $300.0 million in 8.75% senior unsecured notes, due in 2022 (the “Capital Provider Notes”). The Capital Provider Notes may be issued between November 7, 2016 and December 31, 2017 in series of not less than $100.0 million per issue. Borrowings, pursuant to draw down requests as defined in the Senior Note Purchase Agreement, may not be less than $100.0 million and are subject to a 1% original issue discount (“OID”), and are limited by debt covenants and an Indenture Agreement that also impose restrictions on the Company’s ability to borrow additional debt, including amounts drawn under the JPM Revolver, creating an effective borrowing base on all debt facilities as follows:

Prior to the date on which at least $100.0 million aggregate principal amount of the Capital Provider Notes have been issued, additional debt may not exceed the lesser of $25.0 million or the borrowing base, as defined by the JPM Revolver agreement;

ii.

on or after the earlier of (i) the date on which at least $100.0 million aggregate principal amount of the Capital Provider Notes have been issued, but prior to the date on which notes in an aggregate principal amount of the Capital Provider Notes equal to the total $300.0 million commitment have been issued, and prior to the date on which the Commitment Period expires, additional debt may not exceed the lesser of $50.0 million or the borrowing base, as defined by the JPM Revolver agreement; and

iii.

on or after the earlier of the aggregate principal amount of the Capital Provider Notes equal the total $300.0 million commitment or the Commitment period expires, additional debt may not exceed the lesser of (i) the borrowing base as defined by the JPM Revolver agreement or (ii) the greater of $150.0 million and 35.0% of adjusted consolidated net tangible assets, as defined in the Indenture Agreement.

The Capital Provider Notes are also subject to a contingent commitment fee, payable in cash at the end of the Commitment Period, equal to 4.00% of any of the unfunded $300.0 million commitment that is not issued by the end of the Commitment Period (see Note 12, Commitments and Contingencies). Interest on the Capital Provider Notes is payable semi-annually based on the dates specified with each issuance of notes. As of March 31, 2017 and December 31, 2016, there was no balance outstanding on the Capital Provider Notes.

In February 2017, the Company obtained a waiver from the Capital Provider related to the Capital Provider Notes whereas the borrowing capacity under other debt agreements prior to the issuance of at least $100.0 million aggregate principal amount of the Capital Provider Notes was increased from $25.0 million to $60.0 million. The waiver period began upon the execution of the Parsley Energy Contribution Agreement and ends on the earlier of the tenth business day following the outside date of expected closing or the termination of the Parsley Energy Contribution Agreement.

5.	ASSET RETIRMENT OBLIGATIONS

The carrying amount of the Company’s ARO on the Company’s consolidated balance sheets at March 31, 2017 and December 31, 2016 was $5.8 million and $4.0 million, respectively. At the inception of drilling activities, the Company determines the ARO by calculating the present value of estimated future cash flows related to the liability if a reasonable estimate of fair value can be made

and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table provides a reconciliation of the changes in the asset retirement obligations generally associated with future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition for the periods indicated:


	Three Months Ended
	March 31,
	2017		2016
Beginning asset retirement obligations	$	3,956,491	$	1,055,482
Acquisitions		1,784,637		104,338
Accretion expense		55,772		19,214

Ending asset retirement obligations	$	5,796,900	$	1,179,034

As of March 31, 2017, no assets are legally restricted for use in settling asset retirement obligations, and all obligations are classified as long-term in the consolidated balance sheets as we do not expect to incur any of these charges within the next year.

6.	DERIVATIVES AND HEDGING

The Company enters into derivative and hedging contracts to help manage its exposure to cash-flow variability from commodity-price risk inherent in its oil and natural gas production. These include swaps and collars. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings within the consolidated statements of operations.

Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

Each collar transaction has an established price floor and ceiling, and certain collar transactions also include a short put as well. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is below the short put price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short put price.

The following table summarizes all open positions as of March 31, 2017:


	Nine Months Ending			Year Ending
	December 31, 2017			December 31, 2018
Crude contracts:
*Collars ⁽¹⁾:*
Notional volume (Bbl)		28,159,000			33,333,000
Weighted average ceiling price ($/Bbl)	$	59.05		$	61.31
Weighted average floor price ($/Bbl)	$	46.80		$	45.67
*Swaps ⁽¹⁾:*
Notional volume (Bbl)		6,544,000			5,555,500
Weighted average swap price ($/Bbl)	$	54.10		$	55.00
*Basis swap contracts:*
Argus-WTI index swap volume (Bbl)		25,398,000			(38,888,500	)
Price differential ($/Bbl)	$	(0.86	)	$	(0.90	)
Natural gas contracts:
*Swaps ⁽²⁾:*
Notional volume (MMBtu)		42,025,000			13,530,000
Weighted average swap price ($/MMBtu)	$	3.42		$	3.50

¹ – The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.

² – The natural gas derivative contracts are settled based on the month’s average daily NYMEX Henry Hub pricing index.

Derivative Fair Values and Gains (Losses)

The Company’s derivatives are presented on a net, fair value basis in its consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities, as applicable, as permitted under the terms of the Company’s master netting arrangements. See Note 8, Fair Value Measurement, for further discussion related to the fair value of the Company’s derivatives.

The Company has not elected hedge accounting and as such changes in fair value of unrealized positions are recognized in earnings in “Loss on unrealized oil and gas hedges” on the accompanying consolidated statements of operations and “Derivative loss” on the accompanying consolidated statements of cash flows.

The following table summarizes the fair value of our derivative instruments that are included in the accompanying consolidated balance sheet as of March 31, 2017 and December 31, 2016:


	As of March 31, 2017				As of December 31, 2016
	Assets		Liabilities		Assets		Liabilities
Derivative Instruments:
Current amounts
Commodity contracts	$	—	$	1,264,480	$	—	$	2,744,107
Long-term amounts
Commodity contracts		—		3,371,124		—		1,533,254

Total derivative instruments	$	—	$	4,635,604	$	—	$	4,277,361

The following table shows the effects of changes in fair value of our derivative instruments which is recorded through earnings for the three months ended March 31, 2017, in the accompany consolidated statement of operations. The Company did not have any derivative instruments during the three months ended March 31, 2016.


Gain (loss) on derivative instruments:
Commodity derivative instruments	$	(358,243	)

Total	$	(358,243	)

Credit-Risk Related Contingent Features in Derivatives

None of the Company’s derivative instruments contains credit-risk related contingent features. No amounts of collateral were posted by the Company related to net positions as of March 31, 2017 and December 31, 2016.

7.	MEMBERS’ EQUITY AND EQUITY-BASED COMPENSATION

As of September 29, 2016, the date of inception, DEEP issued Series A Units which represent the equity ownership of the Company and Series B Units which represent management incentive units of the Company in accordance with Limited Liability Company Agreement (“LLC Agreement”). In addition, and in conjunction with the Second Amendment to the LLC Agreement, the Company issued Series C Units to another equity partner, the Capital Provider. See below for specific disclosures related to the Company’s Series A, B and C Units. Prior to the formation and inception of DEEP, the Parent had issued its own Series B Units (the “Parent Incentive Units”) to certain employees of the Parent. As of March 31, 2017 and December 31, 2016, the Parent had issued 1,005 Series B Units of which 605 were unvested as of March 31, 2017. The weighted average grant date fair value of the Series B Units is $10,700. These Parent Incentive Units are tied to certain performance metrics and return hurdles of the Parent and its wholly owned subsidiaries including, but not limited to, DEEP. Eighty percent of the Parent Incentive Units vest monthly over a four-year period, with the remaining twenty percent only vesting upon a liquidity event, as defined in the Parent’s Limited Liability Company Agreement. The Parent accounts for these units as equity awards in accordance with ASC 718 and records expense related to these awards based on the grant date fair value of the awards. These units are unrelated to the ownership and Series B Units granted by DEEP. The financial obligation or payout requirements of the Parent Incentive Units belongs to the Parent.

As the employees who were awarded Parent Incentive Units provided services to the assets associated with the Company, a portion of the cost associated with the Parent Incentive Units has been allocated to DEEP. However, as the employees became employees of DEEP subsequent to the Veritas Acquisition, beginning on October 1, 2016, 100% of the future expense is allocated to the consolidated statements of operations of the Company, as discussed below.

For the three months ended March 31, 2016, $0.5 million of the expense associated with the Parent Incentive Unit’s recorded at the Parent has been allocated to the Company and included in general and administrative expense in the accompanying consolidated statements of operations. The expense was allocated during these periods based on the allocation of total capitalized oil and natural gas properties between Lone Star and the Parent’s other wholly owned subsidiary not contributed to the Company at period end. This methodology is consistent with the treatment of other statement of operation items from the Parent that were identified to be allocated to the Company for standalone presentation. The offset to the allocated expense will be included in Parent Company Net Investment, a members’ equity account of the Parent reflecting their invested balance in the Company.

Beginning on October 1, 2016, subsequent to the Veritas Acquisition and going forward, 100% of the expense associated with the Parent Incentive Units will be included in DEEP’s consolidated financial statements, with an offset to the Parent’s equity account. The economic aspects of the Parent Incentive Units relate to the activity and financial metrics of the Parent and its wholly owned subsidiaries, including DEEP. The holders of the Parent Incentive Units were transferred to DEEP subsequent to the Veritas Acquisition, and are now employees of the Company. The expense associated with the Parent Incentive Units allocated to DEEP for the three month ended March 31, 2017 was approximately $0.3 million, and was included in general and administrative expense in the accompanying consolidated statements of operations.

Series A Units – DEEP’s second amended LLC Agreement provides for the issuance of Series A Units, awarded to the two initial parties contributing assets during the formation of the Company at inception, as described herein, as Capital Interest Members of the Company. The Series A Units entitle holders to participate in the net profits of the Company, and grant voting rights and the right to consent or approve on all actions or matters of the Company. At completion of the Veritas Acquisition on September 29, 2016, whereas DEEH contributed all of its Lone Star assets and Veritas contributed its wholly owned subsidiary, Veritas Energy, to the Company, DEEH and Veritas were awarded 731,748,440 and 292,881,554 Series A shares, respectively, for DEEP’s acquisition of these assets. The Series A Units of DEEP have a par value of $1, whereas the initial value of DEEH and Veritas’ equity positions in DEEP are $731,748,440 and $292,881,554, respectively. DEEH’s contribution was governed by the rules pertaining to entities under common control, whereas Veritas’ contribution was an acquisition by the Company. Immediately following the execution of the Veritas Acquisition, the equity interests in DEEP held by DEEH and Veritas were approximately 70.0% and 30.0%, respectively.

Series C Units – DEEP’s second amended LLC Agreement provides for the issuance of Series C Units, to be awarded by and with the approval of the Board of Directors, to create a new class of Capital Interest Members of the Company. On November 7, 2016 and November 9, 2016, in conjunction with the Unit Subscription Agreement with the Capital Provider, a total of 83,110,551 of Series C Units in DEEP, representing approximately 7.5% of DEEP’s equity interests, were sold to the Capital Provider for $150 million. The Series C Units entitle holders to participate in the net profits of the Company; however, holders of Series C Units do not possess voting rights or the right to consent or approve any action or matter. In the event of a liquidation of the Company, the Capital Provider’s Series C Units entitle them to a preferred return, contingent on presence of certain facts as described in Note 11, Commitments and Contingencies. Upon the closing of the Subscription Agreement, the equity interests in DEEP held by DEEH, Veritas and the Capital Provider were approximately 64.75%, 27.75% and 7.5%, respectively.

Capital Provider Preferred Return – In connection with the equity issued pursuant to the Subscription Agreement dated November 7, 2016, the Capital Provider affiliates are entitled to certain liquidation preferences in the event of a liquidity event or certain asset sales, as defined in the Subscription Agreement. These liquidation preferences remain in effect for a 30 month period from the November 7, 2016 effective date of the subscription. The preference entitles the Capital Provider affiliates to the greater of:

•

Actual distributable proceeds from a liquidity event or significant asset sale, less any prior distributions, or

•

A stated hurdle value contained in the Subscription Agreement. Key provisions of the hurdle value include:

For the beginning November 7, 2016 through December 31, 2016, a price equal to 100.0% of the price per share paid by the Capital Provider on November 7, 2016 to acquire their shares in the Company, less any prior distributions;

ii.

For the period beginning January 1, 2017 through July 31, 2017, an amount equal to a 15.0% premium to the price per share paid by the Capital Provider on November 7, 2016 to acquire their shares in the Company, less any prior distributions;

iii.

August 1, 2017 through May 7, 2019, a price equal to 100.0% of the price per share paid by the Capital Provider on November 7, 2016 to acquire their shares in the Company, less any prior distributions.

Prior to December 31, 2016 and in conjunction with customary post-closing matters related to the Veritas Acquisition, certain adjustments per the Contribution Agreement resulted in Veritas’ forfeiting 391,390 Series A Units. As such, Veritas held 292,490,164 Series A Units as of December 31, 2016. Subsequent to December 31, 2016, and in accordance with the Contribution Agreement, Veritas elected to contribute additional equity to the Company to regain its respective 30% ownership, or adjusted pro rata ownership after the addition of the Series C Units. In January 2017, Veritas contributed $21,116,310 to the Company in return for an additional 21,116,310 Series A Units. In addition, and in accordance with the second amended LLC Agreement, the holder of the Series C Units also elected to contribute more equity to the Company to in return keep their pro rata ownership of the Company. A total of 1,737,335 Series C Units were issued as a part of the additional equity contributed. Subsequent to these additional equity contributions, the equity interests in DEEP held by DEEH, Veritas and the Capital Provider were approximately 66.07%, 26.43% and 7.5%, respectively.

Series B Units – DEEP’s second amended LLC Agreement provides for the issuance of Series B Units, as determined and approved by the Board of Directors, to employees of the Company’s. The Series B Units entitle holders to participate in the net profits of the Company, but are subject to various service and performance criteria, and holders of Series B Units do not possess voting rights or the right to consent or approve any action or matter. Upon the occurrence of a liquidity event (as defined in the second amended LLC Agreement) and after the Series A and Series C Members’ capital contributions and Preference Amount has been satisfied, the remaining net profits will be distributed to the Series A, C and B Members in accordance with the terms of the LLC Agreement.

Series B Units vest 80% ratably over a four-year period on an annual basis, with the remaining 20% vesting upon a liquidity event or initial public offering. Series B Units can also vest early upon the occurrence of a liquidity event, initial public offering or in some cases upon termination of employment with DEEP. The Company can issue 1,000,000 Series B Units pursuant to the second amended LLC Agreement upon approval by the Board of Directors. As of March 31, 2017,135,000 Series B Units were issued members of the Company’s new management team of which 123,200 were unvested.

As of March 31, 2017 and December 31, 2016, in relation to the Series B Units issued by DEEP, the Company had approximately $1.2 and $1.0 million, respectively, of total unrecognized compensation costs related to unvested Series B Units which is expected to be recognized over the remaining vesting term, which is approximately four years from the grant date. There is $0.3 million of compensation costs that will be recognized only upon a liquidity event when the remaining 20% of the Series B Units vests as of December 31, 2016. For each of the three months ended March 31, 2017 and 2016, $0.1 million was recognized in non-cash equity-based compensation expense included in “General and administrative” expenses in the accompanying consolidated statements of operations.

The Company accounts for the Series B Units as equity share-based payment awards. Management evaluated the terms of the Series B Units granted, in particular the impact of the performance criteria on the potential value of the Series B Units, and derived a fair value per Series B Unit as of the grant date during 2016.

The fair value of the Series B Units granted was estimated on the grant date utilizing the geometric Brownian motion (“GMB”) model which could accurately include the effects of future capital contributions. Due to the need to include future capital contributions, an option-pricing model was not used. The key assumptions used in our GMB analysis were as follows:

Risk Free Rate

ii.

Expected Volatility and Future Capital Contributions

iii.

Expected Time to Liquidity Event

The risk free rate was derived from the US Treasury strip curve as of the grant date. The expected volatility was based on an analysis of the historical volatilities of the Company’s peer group adjusted for any differences in leverage. The expected time to liquidity event was based on expectations about future behavior.

8.	FAIR VALUE MEASUREMENT

In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The book value of the Company’s current assets and liabilities approximate their fair value due to the short-term nature of the instruments. The Company recognizes its non-financial assets and liabilities, such as ARO and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis. For the three months ended March 31, 2017 and 2016, the Company did not record an impairment on any of its oil and natural gas properties other than normal lease expirations as noted previously. See Note 5, Asset Retirement Obligations above for further discussion on the Company’s ARO.

The Company has not elected to account for any assets or liabilities using the fair value option under ASC 825-10.

Commodity derivative contracts are marked-to-market each month and are thus stated at fair value in the accompanying consolidated balance sheets. The fair values of the Company’s commodity derivative instruments are classified as level 2 measurements as they are calculated using industry standard models based on assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.

The following table summarizes the fair value of the Company’s derivative liabilities according to their fair value hierarchy as of March 31, 2017.


	Fair Value Measurement as of March 31, 2017
	Level 1		Level 2		Level 3		Total
Recurring Fair Value Measurement
Commodity derivative instruments (see Note 6)	$	—	$	4,635,604	$	—	$	4,635,604

	$	—	$	4,635,604	$	—	$	4,635,604

The following table summarizes the fair value of the Company’s derivative liabilities according to their fair value hierarchy as of December 31, 2016.


	Fair Value Measurement as of December 31, 2016
	Level 1		Level 2		Level 3		Total
Recurring Fair Value Measurement
Commodity derivative instruments (see Note 6)	$	—	$	4,277,361	$	—	$	4,277,361

	$	—	$	4,277,361	$	—	$	4,277,361

There were no transfers in to or out of level 2 during the three months ended March 31, 2017 or for the year ended December 31, 2016.

9.	INCOME TAXES

Income Taxes – The Company is not subject to federal or state income taxes, except as noted below, as we are organized as a partnership for income tax purposes and the results of operations are taxable directly to the members. Accordingly, each member is responsible for its share of federal and state income tax.

Texas Margin Tax – The Company is subject to the Texas Margin Tax that requires tax payments at a maximum statutory effective rate of 0.75% on the taxable margin of each taxable entity that does business in Texas. The margin tax qualifies as an income tax under Accounting Standards Codification 740, Income Taxes (FAS 109/FIN 48) (“ASC 740”), which requires us to recognize currently the impact of this tax on the temporary differences between the consolidated financial statement assets and liabilities and their tax basis attributable to such tax. At December 31, 2016 and March 31, 2017, the Company had a greater apportionment rate in Texas as well as greater temporary differences between GAAP and taxable income. As such, as of March 31, 2017 and December 31, 2016, the Company recognized a deferred tax liability in the amount of approximately 2.7 million and $2.6 million, respectively, related to the Texas Margin Tax which is included in the accompanying consolidated balance sheets.

Uncertain Tax Positions – We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions with respect to tax at the partnership level deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the current year. We believe that there are no uncertain tax positions that would impact our operations for the three month periods ended March 31, 2017 and 2016, and that no provision for income tax is required for these consolidated financial statements. However, our conclusions regarding the evaluation are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof. With all tax positions meeting the “more likely than not” threshold under ASC 740, the Company determined that there is no current effect on the consolidated financial statements from a lapse of the statute of limitations as it relates to unrecognized tax benefits. Additionally, the Company’s tax years 2017 and 2016 remain open for examination. As of March 31, 2017 and December 31, 2016, the Company has no amounts related to accrued interest and penalties.

10.

RELATED PARTY TRANSACTIONS

The Company evaluated its relationships, commitments and other agreements with its counterparties, as well as those of the Parent, to determine the existence of related party transactions. The following transactions were determined to be between related parties, such as the PE Sponsor which owns a controlling interest in the Company, certain members of management or entities affiliated therewith.

Transaction Fee

The Parent is party to a Transaction Fee Agreement, dated November 12, 2014 with an affiliate of the PE Sponsor which requires the Parent to pay 1% of the total equity contributed to Double Eagle by the PE Sponsor pursuant to a merger or acquisition of equity or assets if such contribution by The PE Sponsor is $25.0 million or greater (“Transaction Fee”), in exchange for their oversight and expertise related to the financing and completion of such transactions. On September 29, 2016 and in conjunction with the Veritas Acquisition, the Transaction Fee Agreement was terminated. For the three months ended March 31, 2016, any Transaction Fee that could have been incurred by the Parent has been waived by the PE Sponsor.

Services Agreement

The Parent is party to a consulting and advisory services agreement (“Services Agreement”) which requires us to compensate the PE Sponsor equal to the greater of (i) 1% of earnings before interest, income taxes, depletion, depreciation, amortization and exploration expense per quarter, and (ii) $65,200 per quarter (the “Consulting Fee”). The Services Agreement also provides for reimbursement to the PE Sponsor for any reasonable out-of-pocket expenses. On September 29, 2016 and in conjunction with the Veritas Acquisition, the Services Agreement was terminated. For the three months ended March 31, 2016, the Company was allocated approximately $43,000 in Consulting Fees and out-of-pocket expenses which are included in “General and administrative” expenses in the accompanying consolidated statements of operations.

Shared Services Agreement

The Parent is party to an agreement with a management member’s entity whereas DEEP provides certain general and administrative services to Double Eagle Energy Holdings II LLC (“Shared Services Agreement”) for a monthly fee of approximately $14,500 (“Shared Services Expense”). On September 29, 2016 and in conjunction with the Veritas Acquisition, the Share Services Agreement was retained by the Parent and not transferred to the Company. For the three months ended March 31, 2016, the Company incurred approximately $30,000 in Shared Services Expense which is included in general and administrative expense in the accompanying consolidated statements of operations.

Management Services Agreement

The Parent entered into an agreement with another entity owned by the PE Sponsor and management whereas the employees of the Parent would provide employment services to them for a monthly fee of approximately $15,000. On September 29, 2016 and in conjunction with the Veritas Acquisition, the agreement was retained by the Parent and not transferred to the Company. For the three months ended March 31, 2016, the Company’s allocation of the billed amounts were approximately $31,000, for the services performed and included as an offset in general and administrative expense in the accompanying consolidated statements of operations.

Office Lease Agreement

The Company leases office space from management-controlled entities whereas the lease provides office space for general business activity. Rental rates were determined based on comparable rates charged by third parties in surrounding areas. The Company’s lease expense related to these agreements was approximately $144,000 and $29,000 for the three months ended March 31, 2017 and 2016, and is included in general and administrative expense in the accompanying consolidated statements of operations. See Note 11, Commitments and Contingencies for further discussion.

Use of an airplane

The Company rented an airplane for business use for certain members of the Company at various times from a management member’s entity. The airplane is part of a shared fleet, and managed by a third party that invoices the Company for its use based on the operated plane hours at market rate with associated flight crew charges. The Company’s incurred expense was approximately $122,500 and $33,000 for the three months ended March 31, 2017 and 2016, and is included in general and administrative expense in the accompanying consolidated statements of operations.

Acquisitions / Contributions of oil and natural gas properties

From time to time, the Company acquires oil and natural gas properties from other management members’ controlled entities. These transactions are based on the fair value of the assets that are purchased between the Company and a related party. In certain instances, the Company reimburses service costs incurred that related to the acquisition of these assets. For the three months ended March 31, 2016, the Company incurred costs to management members’ controlled entities of approximately $4.5 million for oil and natural gas properties and associated service costs. For the three months ended March 31, 2017, no costs were incurred by management members’ controlled entities for oil and gas properties.

In addition to cash purchases, management members have the ability to offset cash capital contributions with contributions of oil and natural gas properties. Other management members’ controlled entities have similar oil and natural gas operations in the Midland Basin and these entities have been in existence prior to the formation of the Company. During the three months ended March 31, 2017 and 2016, management did not offset any cash capital contributions with contributions of oil and natural gas properties.

11.

COMMITMENTS AND CONTINGENCIES

Litigation - From time-to-time we are party to certain legal, regulatory or administrative proceedings that arise in the ordinary course and are incidental to our business. As of March 31, 2017, there are no such pending proceedings to which we are party to that management believes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

Casualties and Other Risks – The Company maintains coverage in various insurance programs, which provide us with property damage and other coverage which are customary for the nature and scope of our operations.

The Company believes we have adequate insurance coverage, although insurance will not cover every type of loss that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies could increase significantly, and in certain instances, insurance may become unavailable, or available at reduced coverage.

If we were to incur a significant loss for which we were not adequately insured, the loss could have a material impact on our results of operations, cash flow or financial condition. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts our revenues, or which causes us to make a significant expenditure not covered by insurance, could reduce our ability to meet future financial obligations.

Commitments –

The following table summarizes our commitments and obligations as of March 31, 2017:


			Payments Due by Period
	Total		2017		2018		2019		2020		2021		Thereafter
Operating Leases ⁽¹⁾	$	304,764	$	180,455	$	64,041	$	60,268	$	—	$	—	$	—
Deferred lease acquisition costs ⁽²⁾		185,000		—		185,000		—		—		—		—

Total	$	489,764	$	180,455	$	249,041	$	60,268	$	—	$	—	$	—

¹ - The Company leases office buildings under operating leases, as discussed above in Note 10, Related Party Transactions. We recognized approximately $225,000 and $29,000 in rental expense for the three month periods ended March 31, 2017 and 2016, respectively.

² - During 2014, the Company entered into an agreement whereas a certain oil and natural gas lease was assigned to the Company in exchange for five equal annual installment payments of $185,000 to the assignor of the lease. Each annual payment is due by January 15th of the respective year. The Company includes the short term portion of the liability in accounts payable and accrued liabilities and the long term portion in deferred lease acquisition costs in the accompanying consolidated balance sheets.

Contingencies – As of March 31, 2017, contingencies existed for the Company related to the Capital Provider Notes, discussed above in Note 4, Long-term Debt. No amount was recorded as a liability as management was not able to determine the probability.

12.

SUBSEQUENT EVENTS

On April 20, 2017, the Company closed the transaction with Parsley whereas Parsley purchased certain wholly owned subsidiaries of the Company. The aggregate purchase price was approximately $2.8, including certain purchase price adjustments set forth in the Parsley Energy Contribution Agreement. The aggregate purchase price consisted of (i) approximately $1.4 billion in cash and (ii) approximately 39.4 million units in Parsley LLC (“PE Units”) and approximately 39.4 million corresponding shares of Parsley’s Class B common stock. Approximately twelve and a half percent of the cash and PE Unit purchase price was put into

escrow and is expected to release on the first and second anniversary of the closing date subject to customary holdback provisions as outlined in the Parsley Energy Contribution Agreement.

In conjunction with the closing with Parsley, the outstanding balance related to the Credit Agreement was satisfied and the Credit Agreement was terminated. Additionally, the Capital Provider Notes were terminated and the contingent commitment fee for the unfunded portion of the debt was satisfied.

In addition and in conjunction with the closing of the transaction with Parsley, the Company liquidated and filed appropriate dissolution forms. The Company ceased to exist and operate in the crude oil and natural gas exploration, development and production in West Texas.

We have evaluated subsequent events through June 30, 2017, the date the consolidated financial statements were available to be issued.

Pioneer PE Holding LLC - FORM 8-K - EX-99.1 - August 11, 2017

Attached files

Pioneer PE Holding LLC Reports