Edgar Filing: Parsley Energy, Inc.

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

Emerging growth company ¨

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

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-36463

PARSLEY ENERGY, INC.

(Exact name of registrant as specified in its charter)



Delaware		46-4314192
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
303 Colorado Street, Suite 3000 Austin, Texas		78701
(Address of principal executive offices)		(Zip Code)

(737) 704-2300

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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



Title of each class	Trading symbol	Name of each exchange on which listed
Class A common stock, par value $0.01 per share	PE	New York Stock Exchange

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨

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

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

As of May 3, 2019, the registrant had 281,114,084 shares of Class A common stock and 35,538,145 shares of Class B common stock outstanding.

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PARSLEY ENERGY, INC.

TABLE OF CONTENTS



		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Operations	8
	Condensed Consolidated Statements of Changes in Equity	9
	Condensed Consolidated Statements of Cash Flows	10
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 4.	Controls and Procedures	44

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 6.	Exhibits	46
	Signatures	48

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (the “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities, potential financing, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018 (the “Annual Report”) and the risk factors and other cautionary statements contained in our other filings with the United States Securities and Exchange Commission (“SEC”). These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:


•	business strategy;


•	reserves;


•	exploration and development drilling prospects, inventories, projects and programs;


•	ability to replace the reserves we produce through drilling and property acquisitions;


•	financial strategy, liquidity and capital required for our development program;


•	realized oil, natural gas and natural gas liquids (“NGLs”) prices;


•	timing and amount of future production of oil, natural gas and NGLs;


•	hedging strategy and results;


•	future drilling plans;


•	competition and government regulations;


•	ability to obtain permits and governmental approvals;


•	pending legal or environmental matters;


•	marketing of oil, natural gas and NGLs;


•	leasehold, minerals or business acquisitions or divestitures;


•	costs of developing our properties;


•	general economic conditions;


•	credit markets;


•	uncertainty regarding our future operating results; and


•	plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

All forward-looking statements speak only as of the date of this Quarterly Report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements.

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GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

The terms defined in this section are used throughout this Quarterly Report:



(1)	Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.



(2)	Boe. One barrel of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.



(3)	Boe/d. One barrel of oil equivalent per day.



(4)	British thermal unit or Btu. The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.



(5)	Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.



(6)	Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.



(7)	Developed acreage. Acreage spaced or assigned to productive wells, excluding undrilled acreage held by production under the terms of the lease.



(8)	Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.



(9)	Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).



(10)	Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the related property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:



	(i)	Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies.



	(ii)	Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.



	(iii)	Dry hole contributions and bottom hole contributions.



	(iv)	Costs of drilling and equipping exploratory wells.



	(v)	Costs of drilling exploratory-type stratigraphic test wells.



(11)	Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.



(12)	Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.



(13)	Formation. A layer of rock which has distinct characteristics that differ from nearby rock.



(14)	GAAP. Accounting principles generally accepted in the United States.



(15)	Gross acres or gross wells. The total acres or wells, as the case may be, in which an entity owns a working interest.

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(16)	Horizontal drilling. A drilling technique where a well is drilled vertically to a certain depth and then drilled laterally within a specified target zone.



(17)	Identified drilling locations. Potential drilling locations specifically identified by our management based on evaluation of applicable geologic and engineering data accrued over our multi-year historical drilling activities.



(18)	Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.



(19)	LIBOR. London Interbank Offered Rate.



(20)	MBbl. One thousand barrels of crude oil, condensate or NGLs.



(21)	MBoe. One thousand barrels of oil equivalent.



(22)	Mcf. One thousand cubic feet of natural gas.



(23)	MMBtu. One million British thermal units.



(24)	MMcf. One million cubic feet of natural gas.



(25)	Natural gas liquids or NGLs. The combination of ethane, propane, butane, isobutane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.



(26)	Net acres or net wells. The percentage of total acres or wells, as the case may be, an owner has out of a particular number of gross acres or wells. For example, an owner who has a 50% interest in 100 gross acres owns 50 net acres.



(27)	NYMEX. The New York Mercantile Exchange.



(28)	Operator. The entity responsible for the exploration, development and production of a well or lease.



(29)	PE Units. The single class of units that represents the membership interests in Parsley Energy, LLC.



(30)	Proved developed reserves. Proved reserves that can be expected to be recovered:



	(i)	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or



	(ii)	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.



(31)	Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence, within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).



(32)	Proved undeveloped reserves or PUDs. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The following rules apply to PUDs:



	(i)	Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances;

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	(ii)	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time; and



	(iii)	Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.



(33)	Reasonable certainty. A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).



(34)	Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new or existing reservoirs in an attempt to establish new production or increase existing production.



(35)	Reliable technology. A grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.



(36)	Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.



(37)	Reservoir. A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.



(38)	SEC. The United States Securities and Exchange Commission.



(39)	Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.



(40)	Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.



(41)	Wellbore. The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.



(42)	Working interest. The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.



(43)	Workover. Operations on a producing well to restore or increase production.



(44)	WTI. West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

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PART I: FINANCIAL INFORMATION

Item 1: Financial Statements

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2019			December 31, 2018
	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,380		$	163,216
Accounts receivable, net of allowance for doubtful accounts:
Joint interest owners and other	36,657			36,062
Oil, natural gas and NGLs	176,381			138,987
Related parties	2,204			94
Short-term derivative instruments, net	82,327			191,297
Other current assets	9,618			11,056
Total current assets	317,567			540,712
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method	10,327,178			9,948,246
Accumulated depreciation, depletion and impairment	(1,464,040		)	(1,295,098		)
Total oil and natural gas properties, net	8,863,138			8,653,148
Other property, plant and equipment, net	178,854			170,739
Total property, plant and equipment, net	9,041,992			8,823,887
NONCURRENT ASSETS
Operating lease assets, net of accumulated depreciation	157,655			—
Long-term derivative instruments, net	27,301			20,124
Other noncurrent assets	9,632			6,640
Total noncurrent assets	194,588			26,764
TOTAL ASSETS	$	9,554,147		$	9,391,363

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses	$	402,496		$	364,803
Revenue and severance taxes payable	126,339			127,265
Short-term derivative instruments, net	138,784			152,330
Current operating lease liabilities	69,104			—
Other current liabilities	4,657			4,547
Total current liabilities	741,380			648,945
NONCURRENT LIABILITIES
Long-term debt	2,180,616			2,181,667
Deferred tax liability	121,336			131,523
Operating lease liability	92,793			—
Payable pursuant to tax receivable agreement	71,077			68,110
Long-term derivative instruments, net	29,212			16,633
Asset retirement obligations	25,315			24,750
Financing lease liability	1,847			—
Total noncurrent liabilities	2,522,196			2,422,683
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $0.01 par value, 50,000,000 shares authorized, none issued and outstanding	—			—
Common stock
Class A, $0.01 par value, 600,000,000 shares authorized, 281,525,513 shares issued and 280,567,240 shares outstanding at March 31, 2019 and 280,827,038 shares issued and 280,205,293 shares outstanding at December 31, 2018	2,815			2,808
Class B, $0.01 par value, 125,000,000 shares authorized, 36,127,731 and 36,547,731 shares issued and outstanding at March 31, 2019 and December 31, 2018	362			366
Additional paid in capital	5,175,012			5,163,987
Retained earnings	388,582			412,646
Treasury stock, at cost, 958,273 shares and 621,745 shares at March 31, 2019 and December 31, 2018	(17,058		)	(11,749		)
Total stockholders' equity	5,549,713			5,568,058
Noncontrolling interest	740,858			751,677
Total equity	6,290,571			6,319,735
TOTAL LIABILITIES AND EQUITY	$	9,554,147		$	9,391,363

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended March 31,
	2019			2018
	(In thousands, except per share data)
REVENUES
Oil sales	$	368,126		$	331,103
Natural gas sales	14,452			17,424
Natural gas liquids sales	43,785			40,620
Other	1,308			3,594
Total revenues	427,671			392,741
OPERATING EXPENSES
Lease operating expenses	41,172			28,832
Transportation and processing costs	8,257			6,267
Production and ad valorem taxes	27,407			24,186
Depreciation, depletion and amortization	173,723			121,199
General and administrative expenses (including stock-based compensation of $5,322 and $5,069 for the three months ended March 31, 2019 and 2018)	38,037			34,995
Exploration and abandonment costs	22,994			5,411
Acquisition costs	—			4
Accretion of asset retirement obligations	345			354
Loss on sale of property	—			111
Other operating (income) expenses	(811		)	2,175
Total operating expenses	311,124			223,534
OPERATING INCOME	116,547			169,207
OTHER INCOME (EXPENSE)
Interest expense, net	(33,002		)	(31,968		)
Loss on derivatives	(119,687		)	(10,793		)
Change in TRA liability	—			(82		)
Interest income	291			2,123
Other income	58			301
Total other expense, net	(152,340		)	(40,419		)
(LOSS) INCOME BEFORE INCOME TAXES	(35,793		)	128,788
INCOME TAX BENEFIT (EXPENSE)	7,790			(23,325		)
NET (LOSS) INCOME	(28,003		)	105,463
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS	3,939			(22,573		)
NET (LOSS) INCOME ATTRIBUTABLE TO PARSLEY ENERGY, INC. STOCKHOLDERS	$	(24,064	)	$	82,890

Net (loss) income per common share:
Basic	$	(0.09	)	$	0.32
Diluted	$	(0.09	)	$	0.32
Weighted average common shares outstanding:
Basic	278,794			260,654
Diluted	278,794			261,639

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)



	Issued Shares														Shares
	Class A Common Stock	Class B Common Stock		Class A Common Stock		Class B Common Stock			Additional paid in capital			Retained earnings			Treasury stock	Treasury stock			Total stockholders’ equity			Noncontrolling interest			Total equity
	(In thousands)
Balance at December 31, 2018	280,827	36,548		$	2,808	$	366		$	5,163,987		$	412,646		622	$	(11,749	)	$	5,568,058		$	751,677		$	6,319,735
Exchange of PE Units and Class B Common Stock for Class A Common Stock	420	(420	)	4		(4		)	6,277			—			—	—			6,277			(6,277		)	—
Change in net deferred tax liability due to issuance of PE Units by Parsley LLC	—	—		—		—			(571		)	—			—	—			(571		)	—			(571		)
Distribution to owners from consolidated subsidiary	—	—		—					—			—			—	—			—			(603		)	(603		)
Vesting of restricted stock units	279	—		3		—			(3		)	—			—	—			—			—			—
Repurchase of common stock	—	—		—		—			—			—			291	(5,309		)	(5,309		)	—			(5,309		)
Restricted stock forfeited	—	—		—		—			(267		)	—			45	—			(267		)	—			(267		)
Stock-based compensation	—	—		—		—			5,589			—			—	—			5,589			—			5,589
Net loss	—	—		—		—			—			(24,064		)	—	—			(24,064		)	(3,939		)	(28,003		)
Balance at March 31, 2019	281,526	36,128		$	2,815	$	362		$	5,175,012		$	388,582		958	$	(17,058	)	$	5,549,713		$	740,858		$	6,290,571



	Issued Shares													Shares
	Class A Common Stock	Class B Common Stock		Class A Common Stock		Class B Common Stock			Additional paid in capital			Retained earnings		Treasury stock	Treasury stock			Total stockholders’ equity			Noncontrolling interest			Total equity
	(In thousands)
Balance at December 31, 2017	252,420	62,128		$	2,524	$	622		$	4,666,365		$	43,519	159	$	(735	)	$	4,712,295		$	1,168,411		$	5,880,706
Exchange of PE Units and Class B Common Stock for Class A Common Stock	13,396	(13,396	)	135		(135		)	255,398			—		—	—			255,398			(255,398		)	—
Change in net deferred tax liability due to issuance of PE Units by Parsley LLC	—	—		—		—			(15,123		)	—		—	—			(15,123		)	—			(15,123		)
Issuance of restricted stock	750	—		8		—			(8		)	—		—	—			—			—			—
Vesting of restricted stock units	886	—		8		—			(8		)	—		—	—			—			—			—
Repurchase of common stock	—	—		—		—			—			—		279	(6,465		)	(6,465		)	—			(6,465		)
Restricted stock forfeited	—	—		—		—			(40		)	—		—	—			(40		)	—			(40		)
Stock-based compensation	—	—		—		—			5,109			—		—	—			5,109			—			5,109
Conversion of restricted stock units to restricted stock awards	1,098	—		11		—			(11		)	—		—	—			—			—			—
Net income	—	—		—		—			—			82,890		—	—			82,890			22,573			105,463
Balance at March 31, 2018	268,550	48,732		$	2,686	$	487		$	4,911,682		$	126,409	438	$	(7,200	)	$	5,034,064		$	935,586		$	5,969,650

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
	2019			2018
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(28,003	)	$	105,463
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	173,723			121,199
Leasehold abandonments and impairments	22,189			5,179
Accretion of asset retirement obligations	345			354
Loss on sale of property	—			111
Stock-based compensation	5,322			5,069
Deferred income tax (benefit) expense	(7,790		)	23,325
Change in TRA liability	—			82
Loss on derivatives	119,687			10,793
Net cash paid for derivative settlements	(5,072		)	(1,903		)
Net cash paid for option premiums	(10,440		)	(13,506		)
Other	1,056			1,096
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable	(37,989		)	(43,214		)
Accounts receivable—related parties	(2,110		)	77
Other current assets	1,438			3,835
Other noncurrent assets	(3,308		)	(635		)
Accounts payable and accrued expenses	(15,063		)	(5,427		)
Revenue and severance taxes payable	(926		)	15,057
Net cash provided by operating activities	213,059			226,955
CASH FLOWS FROM INVESTING ACTIVITIES:
Development of oil and natural gas properties	(352,650		)	(411,073		)
Acquisitions of oil and natural gas properties	(13,846		)	(27,447		)
Additions to other property and equipment	(11,106		)	(28,248		)
Proceeds from sales of property, plant and equipment	17,486			43,228
Other	809			349
Net cash used in investing activities	(359,307		)	(423,191		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under long-term debt	120,000			—
Payments on long-term debt	(120,000		)	(694		)
Payments on financing lease obligations	(676		)	—
Debt issuance costs	—			(32		)
Repurchase of common stock	(5,309		)	(6,465		)
Distributions to owners from consolidated subsidiary	(603		)	—
Net cash used in financing activities	(6,588		)	(7,191		)
Net decrease in cash, cash equivalents and restricted cash	(152,836		)	(203,427		)
Cash, cash equivalents and restricted cash at beginning of period	163,216			554,189
Cash, cash equivalents and restricted cash at end of period	$	10,380		$	350,762
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	(30,493	)	$	(29,455	)
Cash received for income taxes	$	240		$	—
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate	$	219		$	359
Additions to oil and natural gas properties - change in capital accruals	$	53,654		$	13,013
Net premiums on options that settled during the period	$	(9,516	)	$	(16,526	)

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1. ORGANIZATION AND NATURE OF OPERATIONS

Parsley Energy, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company”) is an independent oil and natural gas company focused on the acquisition, development, exploration and production of unconventional oil and natural gas properties in the Permian Basin. The Permian Basin is located in west Texas and southeastern New Mexico and is characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons, extensive production histories, long-lived reserves and historically high drilling success rates. The Company’s properties are located in two sub areas of the Permian Basin, the Midland Basin and the Delaware Basin, where, given the associated returns, it focuses predominantly on horizontal development drilling.

NOTE 2. SUMMARY OF ACCOUNTING POLICIES

These condensed consolidated financial statements include the accounts of (i) the Company, (ii) Parsley Energy, LLC, the Company’s majority owned subsidiary (“Parsley LLC”), (iii) the direct and indirect wholly owned subsidiaries of Parsley LLC, and (iv) Pacesetter Drilling, LLC (“Pacesetter”), an indirect, majority owned subsidiary of Parsley LLC, of which Parsley LLC owns, indirectly, a 63.0% interest. Parsley LLC also owns, indirectly, a 42.5% noncontrolling interest in Spraberry Production Services, LLC (“SPS”). The Company accounts for its investment in SPS using the equity method of accounting. All significant intercompany and intra-company balances and transactions have been eliminated.

Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted from this Quarterly Report, as permitted by SEC rules and regulations. The Company believes the disclosures made in this Quarterly Report are adequate to make the information herein not misleading. The Company recommends that these condensed consolidated financial statements should be read in conjunction with its audited consolidated financial statements and related notes thereto included in the Annual Report.

The interim data includes all adjustments, consisting only of normal recurring adjustments, that are, in the opinion of the Company’s management, necessary for a fair statement of the results for the interim periods presented. The results of operations for the three months ended March 31, 2019 are not necessarily indicative of the Company’s operating results for the entire fiscal year ending December 31, 2019.

Use of Estimates

These condensed consolidated financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires the Company to (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (ii) make estimates and assumptions that affect the reported amounts of assets and liabilities, the 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. The Company’s management believes the major estimates and assumptions impacting the Company’s condensed consolidated financial statements are the following:


•	estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization (“DD&A”) and impairment of capitalized costs of oil and natural gas properties;


•	estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;


•	impairment of developed and undeveloped properties and other assets;


•	depreciation of property and equipment; and


•	valuation of commodity derivative instruments.

Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas

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proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

Significant Accounting Policies

For a complete description of the Company’s significant accounting policies, see Note 2—Summary of Significant Accounting Policies in the Annual Report.

Accounts Receivable

The Company had an allowance for doubtful accounts of $2.8 million at each of March 31, 2019 and December 31, 2018.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current presentation. Such reclassifications had no effect on the Company’s previously reported net income, earnings per share, cash flows or retained earnings.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; ASU No. 2018-11, Targeted Improvements; and ASU No. 2018-20 Leases (Topic 842). The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application. An entity may choose to use either (1) its effective date or (2) the beginning of the earliest comparative period presented in the financial statements as its date of initial application. If an entity chooses the second option, the transition requirements for existing leases also apply to leases entered into between the date of initial application and the effective date. The entity must also recast its comparative period financial statements and provide the disclosures required by the new standard for the comparative periods. The Company adopted the new standard on January 1, 2019 using the modified retrospective transition approach and used the effective date as the Company’s date of initial application.

The new standard provides a number of optional practical expedients in transition. The Company has elected to apply the practical expedient to use hindsight with respect to determining lease term and in assessing any impairment of ROU assets for existing leases. The Company did not elect to apply the “package practical expedients.” The new standard also provides practical expedients for an entity’s ongoing accounting. The Company elected the short-term lease recognition exemption for all leases that qualify. This means, for those leases that qualify, the Company did not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. The Company has elected the practical expedient to not separate lease and non-lease components for all of its leases other than leases of vehicles.

Adoption of the new standard resulted in the Company recording additional operating net ROU assets and lease liabilities of $143.9 million. The current portion of the operating lease liability is included in Current operating lease liabilities and the noncurrent portion in Operating lease liabilities on the Company’s condensed consolidated balance sheets. Balances associated with finance leases have been reclassified to include the current portion in Other current liabilities and the noncurrent portion in Financing lease liabilities on the Company’s condensed consolidated balance sheets. The adoption of this standard did not materially impact the Company’s consolidated statements of operations or cash flows. Please refer to Note 9—Leases for additional discussion.

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NOTE 3. REVENUE FROM CONTRACTS WITH CUSTOMERS

In accordance with ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”), revenue is measured based on considerations specified in contracts with customers, excluding any sales incentives or amounts collected on behalf of third parties. The Company recognizes revenue when a performance obligation is satisfied by the transfer of control over a product to the ultimate customer. Sales of oil, natural gas and NGLs are recognized at the time that control of the product is transferred to the customer and collectability is reasonably assured. Generally, the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the prices of the Company’s oil, natural gas, and NGLs fluctuate to remain competitive with other available oil, natural gas, and NGLs supplies. The Company reports revenues disaggregated by product on its condensed consolidated statements of operations.

Oil Sales

Under the Company’s oil sales contracts, the Company sells oil production at or near the wellhead and the Company collects an agreed-upon index price, net of pricing differentials. The Company recognizes revenue at the net price received when control transfers to the purchaser at or near the wellhead.

Natural Gas and NGLs Sales

Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing company at the wellhead or the inlet of the midstream processing company’s system. The midstream processing company gathers and processes the natural gas and remits proceeds to the Company for the resulting natural gas and NGLs sales. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction, which includes considerations of product redelivery, take-in-kind rights and risk of loss. For those contracts where the Company has concluded that control of the product transfers at the tailgate of the plant, meaning that the Company is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation and processing fees presented as Transportation and processing costs on the Company’s condensed consolidated statements of operations. Alternatively, for those contracts where the Company has concluded control of the product transfers at the inlet of the plant, meaning that the Company is the agent and the midstream processing company is the Company’s customer, the Company recognizes natural gas and NGLs sales based on the net amount of proceeds received from the midstream processing company. The Company also determined that losses associated with shrinkage and line loss (“FL&U”) occur prior to the change in control. As a result, natural gas and NGLs sales are presented net of FL&U costs. Revenues associated with natural gas and NGLs sales at the plant inlet are considered a single combined performance obligation. During the three months ended March 31, 2019 and 2018, the applicable line items on the condensed consolidated statements of operations include $2.9 million and $4.7 million of natural gas and $7.2 million and $10.5 million NGLs sales, respectively, completed at the plant inlet.

Contract Balances

Under the Company’s product sales contracts, the Company invoices customers once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. Settlement statements for certain natural gas and NGLs sales, however, may not be received for 30 to 90 days after the date production is delivered, and as a result the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. In these situations, the Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between the Company’s revenue estimates and actual revenue received have historically been insignificant. For each of the three months ended March 31, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Instruments and Concentration of Risk

Objective and Strategy

The Company utilizes derivative financial instruments, including put spread options, three-way collars, two-way collars, commodity swap contracts and basis swap contracts to (i) reduce the effect of price volatility on the Company’s oil and natural gas revenues and (ii) support the Company’s annual capital budgeting and expenditure plans.

Oil Production Derivative Activities

The Company’s material physical sales contracts governing its oil production are typically correlated with NYMEX WTI, including Cushing (“WTI Cushing”), Midland (“WTI Midland”) and Magellan East Houston (“WTI MEH”) oil prices. The Company uses put spread options, three-way collars and two-way collars to manage oil price volatility. The Company uses basis swap contracts to reduce basis risk between NYMEX WTI prices and the actual index prices at which the oil is sold.

As of March 31, 2019, the Company had the following outstanding oil derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.



Put spreads⁽¹⁾	Nine Months Ending December 31, 2019							Year Ending December 31, 2020
	WTI Cushing		WTI Midland			WTI MEH		WTI Cushing		WTI Midland		WTI MEH
Volume (MBbls)	4,650		2,250			1,800		—		—		900
Long put price (per Bbl)	$	57.90	$	54.33		$	65.00	$	—	$	—	$	70.00
Short put price (per Bbl)	$	48.55	$	44.33		$	55.00	$	—	$	—	$	60.00

Three-way collars	Nine Months Ending December 31, 2019							Year Ending December 31, 2020
	WTI Cushing		WTI Midland			WTI MEH		WTI Cushing		WTI Midland		WTI MEH
Volume (MBbls)	6,750		900			—		—		—		4,800
Short call price (per Bbl)	$	72.17	$	64.65		$	—	$	—	$	—	$	75.88
Long put price (per Bbl)	$	51.00	$	50.00		$	—	$	—	$	—	$	59.69
Short put price (per Bbl)	$	42.33	$	45.00		$	—	$	—	$	—	$	49.69

Two-way collars	Nine Months Ending December 31, 2019
	WTI Cushing
Volume (MBbls)	6,150
Short call price (per Bbl)	$	58.08
Long put price (per Bbl)	$	54.31

Basis swaps	Nine Months Ending December 31, 2019									Year Ending December 31, 2020
	Volume (MBbls)		Basis Differential (per Bbl)							Volume (MBbls)		Basis Differential (per Bbl)
Basis swap - WTI Midland-WTI Cushing index⁽²⁾	8,910		$	(2.22	)					900		$	0.25
Basis swap - WTI Houston-WTI Cushing index⁽²⁾	585		$	5.10						—		$	—

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(1)	Excludes 3,150 notional MBbls with a fair value of $1.4 million related to amounts recognized under master netting agreements with derivative counterparties.
(2)	Swaps that fix the basis differentials representing the index prices at which the Company sells its oil produced in the Permian Basin less the WTI Cushing price.

Natural Gas Production Derivative Activities

All material physical sales contracts governing the Company’s natural gas production are tied directly or indirectly to NYMEX Henry Hub (“Henry Hub”) natural gas prices or regional index prices where the natural gas is sold. The Company uses three-way collars and commodity swap contracts to manage natural gas price volatility.

The following table sets forth the volumes associated with the Company’s outstanding natural gas derivative contracts expiring during the period indicated and the weighted average natural gas prices for those contracts:



Three-way collars	Nine Months Ending December 31, 2019
	NYMEX Henry Hub
Volume (MMbtu)	9,000,000
Short call price (per MMbtu)	$	3.93
Long put price (per MMbtu)	$	3.00
Short put price (per MMbtu)	$	2.50

	Volume (MMbtu)		Basis Differential (per MMbtu)
Basis swap - Waha⁽¹⁾	9,000,000		$	(1.78	)



(1	)	Swaps that fix the basis differentials representing the index prices at which the Company sells its natural gas produced in the Permian Basin less the Henry Hub price.

Effect of Derivative Instruments on the Condensed Consolidated Financial Statements

All of the Company’s derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The table below summarizes the Company’s losses on derivative instruments for the three months ended March 31, 2019 and 2018 (in thousands):



	Three Months Ended March 31,
	2019			2018
Changes in fair value of derivative instruments	$	(111,348	)	(7,920		)
Net derivative settlements	(8,339		)	(2,873		)
Loss on derivatives	$	(119,687	)	$	(10,793	)

Net premiums on options that settled during the period ⁽¹⁾	$	(9,516	)	$	(16,526	)



(1)	The net premiums on options that settled during the period represents the cumulative cost of premiums paid and received on positions purchased and sold, which expired during the current period. These amounts are included in Loss on derivatives on the Company’s consolidated statements of operations.

The Company classifies the fair value amounts of derivative assets and liabilities as gross current or noncurrent derivative assets or gross current or noncurrent derivative liabilities, whichever the case may be, excluding those amounts netted under master netting agreements. The fair value of the derivative instruments is discussed in Note 16—Disclosures About Fair Value of Financial Instruments. The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and liabilities at settlement or in the event of default under the agreements. Additionally, the Company maintains accounts with its brokers to facilitate financial derivative transactions in support of its

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risk management activities. Based on the value of the Company’s positions in these accounts and the associated margin requirements, the Company may be required to deposit cash into these broker accounts. During each of the three months ended March 31, 2019 and 2018, the Company did not receive or post any material margins in connection with collateralizing its derivative positions.

The following table presents the Company’s net exposure from its offsetting derivative asset and liability positions, as well as option premiums payable and receivable as of the reporting dates indicated (in thousands):



	Gross Amount			Netting Adjustments			Net Exposure
March 31, 2019
Derivative assets with right of offset or master netting agreements	$	111,068		$	(1,440	)	$	109,628
Derivative liabilities with right of offset or master netting agreements	(169,436		)	1,440			(167,996		)

December 31, 2018
Derivative assets with right of offset or master netting agreements	$	236,431		$	(25,010	)	$	211,421
Derivative liabilities with right of offset or master netting agreements	(193,973		)	25,010			(168,963		)

Concentration of Credit Risk

The Company believes that it has limited credit risk with respect to its exchange-traded contracts, as such contracts are subject to financial safeguards and transaction guarantees through NYMEX. Over-the-counter traded options expose the Company to counterparty credit risk. These over-the-counter options are entered into with large multinational financial institutions with investment grade credit ratings or through brokers that require all the transaction parties to collateralize their open option positions. The gross and net credit exposure from the Company’s commodity derivative contracts as of March 31, 2019 and December 31, 2018 is summarized in the preceding table.

The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines and assesses the impact on fair values of its counterparties’ creditworthiness. The Company enters into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with its derivative counterparties. The terms of the ISDA Agreements provide the Company and its counterparties and brokers with rights of net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The Company routinely exercises its contractual right to offset realized gains against realized losses when settling with derivative counterparties. If the Company believes a counterparty’s creditworthiness has declined or is suspect, it may seek to novate the applicable ISDA Agreement to another financial institution that has an ISDA Agreement in place with the Company. The Company did not incur any losses due to counterparty nonperformance during the three months ended March 31, 2019 or the year ended December 31, 2018.

Credit Risk Related Contingent Features in Derivatives

Certain commodity derivative instruments contain provisions that require the Company to either post additional collateral or collateral support (including letters of credit, security interests in an asset, or a performance bond or guarantee), or immediately settle any outstanding liability balances, upon the occurrence of a specified credit risk related event. These events, which are set forth in the Company’s existing commodity derivative contracts, include, among others, downgrades in the credit ratings of the Company and its affiliates, events of default under the Company’s revolving credit agreement (the “Revolving Credit Agreement”), and the release of collateral (other than as provided under the terms of the Revolving Credit Agreement). Although the Company could be required to post additional collateral or collateral support, or immediately settle any outstanding liability balances, under such conditions, the Company seeks to reduce its potential risk by entering into commodity derivative contracts with several different counterparties.

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NOTE 5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment includes the following (in thousands):



	March 31, 2019			December 31, 2018
Oil and natural gas properties:
Subject to depletion	$	7,083,324		$	6,659,444
Not subject to depletion
Incurred in 2019	333,629			—
Incurred in 2018	402,583			677,920
Incurred in 2017 and prior	2,507,642			2,610,882
Total not subject to depletion	3,243,854			3,288,802
Oil and natural gas properties, successful efforts method	10,327,178			9,948,246
Less accumulated depreciation, depletion and impairment	(1,464,040		)	(1,295,098		)
Total oil and natural gas properties, net	8,863,138			8,653,148
Other property, plant and equipment	218,002			206,662
Less accumulated depreciation	(39,148		)	(35,923		)
Other property, plant and equipment, net	178,854			170,739
Total property, plant and equipment, net	$	9,041,992		$	8,823,887

Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs and current drilling projects.

As the Company’s exploration and development work progresses and the reserves on the Company’s properties are proven, capitalized costs attributed to the properties and mineral interests are subject to DD&A. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and natural gas reserves related to the associated reservoir. Depletion expense on capitalized oil and natural gas properties was $169.9 million and $117.6 million, for the three months ended March 31, 2019 and 2018, respectively. The Company had no exploratory wells in progress at March 31, 2019 or December 31, 2018.

NOTE 6. ACQUISITIONS AND DIVESTITURES

Acquisitions

During the three months ended March 31, 2019, the Company incurred costs of $13.8 million related to the purchase of leasehold acreage. During the three months ended March 31, 2019, the Company reflected $11.7 million as part of costs not subject to depletion and $2.1 million as part of costs subject to depletion within its oil and natural gas properties.

During the three months ended March 31, 2018, the Company incurred costs of $27.4 million related to the acquisition of leasehold acreage. During the three months ended March 31, 2018, the Company reflected $23.9 million as part of costs not subject to depletion and $3.5 million as part of costs subject to depletion within its oil and natural gas properties.

During each of the three months ended March 31, 2019 and 2018, the Company exchanged certain leasehold acreage and oil and natural gas properties with third parties, with no gain or loss recognized.

Divestitures

During the three months ended March 31, 2019, the Company closed sales of certain leasehold acreage for proceeds of $17.5 million, including customary purchase price adjustments. Upon closing these sales, the Company recognized no gain or loss in accordance with the guidance for partial sales of oil and natural gas properties under ASC Topic 932, Extractive Activities—Oil and Gas (“ASC 932”).

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During the three months ended March 31, 2018, the Company sold certain acreage for total proceeds of $43.2 million, subject to customary purchase price adjustments. Upon closing the sale, the Company recognized no gain or loss in accordance with the guidance for partial sales of oil and natural gas properties under ASC 932.

NOTE 7. ASSET RETIREMENT OBLIGATIONS

For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely the plugging and abandonment of wells and land remediation. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred 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. The liability is accreted to its then present value each period. If the liability is settled for an amount other than the recorded amount, the difference is recorded in Other income (expense) in the consolidated statements of operations.

The following table summarizes the changes in the Company’s asset retirement obligations for the three months ended March 31, 2019 (in thousands):



	March 31, 2019
Asset retirement obligations, beginning of period	$	26,884
Additional liabilities incurred	221
Accretion expense	345
Revision of estimates	(2		)
Asset retirement obligations, end of period	$	27,448

NOTE 8. DEBT

The Company’s debt consisted of the following as of the dates indicated (in thousands):



	March 31, 2019			December 31, 2018
Revolving Credit Agreement	$	—		$	—
6.250% senior unsecured notes due 2024	400,000			400,000
5.375% senior unsecured notes due 2025	650,000			650,000
5.250% senior unsecured notes due 2025	450,000			450,000
5.625% senior unsecured notes due 2027	700,000			700,000
Capital leases⁽¹⁾	—			4,202
Total debt	2,200,000			2,204,202
Debt issuance costs on senior unsecured notes	(22,050		)	(22,918		)
Premium on senior unsecured notes	2,666			2,796
Less: current portion of debt	—			(2,413		)
Total long-term debt	$	2,180,616		$	2,181,667


(1)	As a result of the implementation of ASU No. 2016-02, Leases (Topic 842), as of March 31, 2019, capital leases have been reclassified to include the current portion in Other current liabilities and the noncurrent portion in Financing lease liabilities on the Company’s condensed consolidated balance sheets. Please refer to Note 9—Leases for additional discussion.

Revolving Credit Agreement

As of March 31, 2019, the borrowing base under the Revolving Credit Agreement was $2.3 billion with a commitment level of $1.0 billion. There were no borrowings outstanding and $8.7 million in letters of credit outstanding as of March 31, 2019, resulting in availability of $991.3 million. The amount Parsley LLC is able to borrow under the Revolving Credit Agreement is subject to compliance with the financial covenants, satisfaction of various conditions precedent to borrowing and other provisions of the Revolving Credit Agreement. See Note 17—Subsequent Events for information regarding the terms of

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the Seventh Amendment (“the Seventh Amendment”) to the Revolving Credit Agreement, which was entered to on April 23, 2019.

As of March 31, 2019, letters of credit under the Revolving Credit Agreement bear a 1.25% weighted average interest rate.

Covenant Compliance

The Revolving Credit Agreement and the indentures governing the 5.625% senior unsecured notes due 2027 (the “2027 Notes”), the 5.250% senior unsecured notes due 2025 (the “New 2025 Notes”), the 5.375% senior unsecured notes due 2025 (the “2025 Notes”), and the 6.250% senior unsecured notes due 2024 (the “2024 Notes” and, together with the 2027 Notes, the New 2025 Notes and the 2025 Notes, the “Notes”) restrict the Company’s ability and the ability of certain of its subsidiaries to, among other things: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict its restricted subsidiaries from issuing dividends or making other payments to the Company; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time the Notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default or event of default (as defined in the indentures) has occurred and is continuing, many of the foregoing covenants pertaining to the Notes will be suspended. If the ratings on the Notes were to subsequently decline to below investment grade, the suspended covenants would be reinstated.

As of March 31, 2019, the Company was in compliance with all required covenants under the Revolving Credit Agreement and each of the indentures governing the Notes.

Interest Expense

The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2019 and 2018 (in thousands):



	Three Months Ended March 31,
	2019			2018
Cash payments for interest	$	30,493		$	29,455
Change in interest accrual	1,453			1,453
Amortization of deferred loan origination costs	1,185			1,189
Amortization of bond premium	(129		)	(129		)
Total interest expense, net	$	33,002		$	31,968

NOTE 9. LEASES

The Company has entered into operating leases for drilling rigs, real estate, and other field and office equipment, as well as finance leases for vehicles. The Company’s leases have remaining lease terms of up to 26 years, some of which include options to extend for up to 14 years, and some of which include options to terminate within one year. The exercise of lease renewal and termination options are at the Company’s sole discretion. For purposes of calculating operating lease liabilities, the Company’s leases are deemed not to include an option to extend the lease term until it is reasonably certain that the Company will exercise that option. Certain finance leases also include options to purchase the leased asset.

The Company determines whether a contract arrangement contains a lease at inception. The lease classification and lease measurement are determined upon lease commencement. The lease commencement date is evaluated based on when the key lease terms are available and when the Company takes possession of the underlying asset. The Company's lease agreements do not contain any material residual value guarantees or material restrictive covenants.

ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. The lease payments represent gross payments to vendors which, for certain of our operating assets, are offset by amounts received from other working interest owners. Because the majority of the Company’s leases do not

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provide an implicit rate of return, the Company uses its incremental borrowing rate based on the information available at the commencement date of the lease in determining the present value of lease payments. The Company has operating lease agreements with lease and non-lease components that are accounted for as a single lease component. For vehicle leases, the Company accounts for the lease and non-lease components separately. The Company subleases certain of its real estate to third parties for office and parking space.

The Company recognizes lease costs on a straight-line basis over the term of the lease. The depreciable life of assets is limited by the non-cancellable term of the lease, unless there is a transfer of title or purchase option reasonably certain of exercise. The components of the Company’s lease costs as of March 31, 2019 were as follows:



	Three Months Ended March 31, 2019
	(In thousands)
Finance lease costs:
Amortization of right-of-use assets	$	681
Interest on lease liabilities	60
Operating lease costs⁽¹⁾	23,428
Short-term lease costs⁽²⁾	6,047
Variable lease costs⁽³⁾	3,738
Sublease income	(97		)
Total lease costs	$	33,857


(1)	For the three months ended March 31, 2019, operating lease costs are included in the following line items on our condensed consolidated financial statements: $19.5 million is capitalized as part of Oil and natural gas properties, $2.6 million is included in General and administrative expenses, and $1.3 million is included in Lease operating expenses.


(2)	Short-term lease costs represent costs related to leases with a contract term of one year or less. For the three months ended March 31, 2019, short-term lease costs are included in the following line items on our condensed consolidated financial statements: $2.8 million is capitalized as part of Oil and natural gas properties and $3.2 million is included in Lease operating expenses.

(3)

Variable lease payments that are not dependent on an index or rate are not included in the lease liability or ROU assets. For the three months ended March 31, 2019, variable lease costs are included in the following line items on our condensed consolidated financial statements: $2.4 million is capitalized as part of Oil and natural gas properties and $1.3 million is included in General and administrative expenses.

Supplemental cash flow information related to the Company’s leases as of March 31, 2019 was as follows:



	Three Months Ended March 31, 2019
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	3,796
Investing cash flows from operating leases	$	19,176
Operating cash flows from finance leases	$	60
Financing cash flows from finance leases	$	676

Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	44,936
Finance leases	$	1,046

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Supplemental balance sheet information related to the Company’s leases as of March 31, 2019 was as follows (in thousands):



	March 31, 2019
Operating leases
Assets
Operating lease assets, net of accumulated depreciation	$	157,655
Liabilities
Current operating lease liabilities	(69,104		)
Operating lease liability	(92,793		)
Total operating lease liabilities	$	(161,897	)

Finance leases
Assets
Property and equipment, gross	$	9,428
Accumulated depreciation	(5,109		)
Property and equipment, net	$	4,319
Liabilities
Other current liabilities	$	(2,523	)
Financing lease liability	(1,847		)
Total finance liabilities	$	(4,370	)

Weighted average remaining lease term (in years)
Operating leases	3.2
Finance leases	2.0

Weighted average discount rate
Operating leases	4.8		%
Finance leases	5.4		%

Maturities of Lease Liabilities

Maturities of the Company’s lease liabilities as of March 31, 2019 were as follows (in thousands):



	Operating leases			Finance leases
2019	$	58,909		$	2,113
2020	56,023			1,753
2021	27,591			667
2022	11,311			77
2023	8,616			13
Thereafter	12,700			—
Total lease payments	$	175,150		$	4,623
Less imputed interest	(13,253		)	(253		)
Total lease obligations	$	161,897		$	4,370
Less: Current obligations	$	(69,104	)	$	(2,523	)
Long-term lease obligations	$	92,793		$	1,847

As of March 31, 2019, the Company had an additional $198.8 million of operating lease liabilities with respect to leases that have not commenced, including $170.9 million associated with a real estate lease with a 12-year lease term that will

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commence between fiscal years 2021 and 2022. Additionally, $27.9 million is associated with contracts for operating field equipment.

NOTE 10. EQUITY

Earnings per Share

Basic earnings per share (“EPS”) measures the performance of an entity over the reporting period. Diluted EPS measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding PE Units (and corresponding shares of the Company’s Class B common stock, par value $0.01 per share (“Class B common stock”)), and the treasury stock method to determine the potential dilutive effect of vesting of its outstanding restricted stock and restricted stock units. For each of the three months ended March 31, 2019 and 2018, Class B common stock was not recognized in dilutive EPS calculations as the effect would have been antidilutive. For the three months ended March 31, 2019, restricted stock and restricted stock units were not recognized in dilutive EPS calculations as the effect would have been antidilutive.

The following table reflects the allocation of net income to common stockholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period:



	Three Months Ended March 31,
	2019			2018
Basic EPS (in thousands, except per share data)
Numerator:
Basic net (loss) income attributable to Parsley Energy, Inc. Stockholders	$	(24,064	)	$	82,890
Denominator:
Basic weighted average shares outstanding	278,794			260,654
Basic EPS attributable to Parsley Energy, Inc. Stockholders	$	(0.09	)	$	0.32
Diluted EPS
Numerator:
Net (loss) income attributable to Parsley Energy, Inc. Stockholders	(24,064		)	82,890
Diluted net (loss) income attributable to Parsley Energy, Inc. Stockholders	$	(24,064	)	$	82,890
Denominator:
Basic weighted average shares outstanding	278,794			260,654
Effect of dilutive securities:
Time-Based Restricted Stock and Time-Based Restricted Stock Units	—			985
Diluted weighted average shares outstanding ⁽¹⁾	278,794			261,639
Diluted EPS attributable to Parsley Energy, Inc. Stockholders	$	(0.09	)	$	0.32

(1)

As of March 31, 2019 and 2018, there were 1,212,387 and 1,356,522 shares or units of performance-based restricted awards, respectively, that could vest in the future based on predetermined performance and market goals. These awards were not included in the computation of EPS for either the three months ended March 31, 2019 or 2018, because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period.

Noncontrolling Interest

During the three months ended March 31, 2019, an officer of the Company, who is a holder of PE Units (a “PE Unit Holder”), exercised his right to exchange PE Units under the Third Amended and Restated Limited Liability Company Agreement of Parsley LLC (the “Parsley LLC Agreement”), electing to exchange 420,000 PE Units (and a corresponding number of shares of Class B common stock) for 420,000 shares of the Company’s Class A common stock, par value $0.01 per

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share (“Class A common stock”). In turn, the Company exercised its call right under the Parsley LLC Agreement, electing to issue Class A common stock directly to the exchanging PE Unit Holder in satisfaction of his election notice. As a result of this exchange of PE Units (and corresponding shares of Class B common stock) for shares of Class A common stock during the three months ended March 31, 2019, the Company’s ownership in Parsley LLC increased from 88.5% to 88.6% and the ownership of the PE Unit Holders in Parsley LLC decreased from 11.5% to 11.4%. Because these changes in the Company’s ownership interest in Parsley LLC did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, Consolidation, which requires that any differences between the carrying value of the Company’s basis in Parsley LLC and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. The Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the PE Unit Holders as a noncontrolling interest.

The following table summarizes the net (loss) income attributable to noncontrolling interests (in thousands):



	Three Months Ended March 31,
	2019			2018
Net (loss) income attributable to the noncontrolling interests of:
Parsley LLC	$	(3,941	)	$	22,415
Pacesetter Drilling, LLC	2			158
Total net (loss) income attributable to noncontrolling interest	$	(3,939	)	$	22,573

NOTE 11. STOCK-BASED COMPENSATION

In connection with the Company’s initial public offering (the “IPO”), the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan for employees, directors and consultants of the Company. Refer to “Compensation Discussion and Analysis-Elements of Compensation-Incentive Compensation” in the Company’s Proxy Statement filed on Schedule 14A for the 2019 Annual Meeting of Stockholders for additional information related to this equity based compensation plan.

On February 12, 2018, the performance-based restricted stock units (“PSUs”) granted in 2016 and 2017 were converted into performance-based restricted stock awards (“PSAs”) at 200% of the target payout for such awards. Similarly, certain of the time-based restricted stock units (“RSUs”) granted in 2016 were also converted to time-based restricted stock awards (“RSAs”) on February 12, 2018. As converted, the PSAs and RSAs are intended to be economically identical to the pre-conversion awards with the same material terms and conditions, including vesting schedules and performance criteria.

Stock-based compensation expense recorded for each type of stock-based compensation award activity for the three months ended March 31, 2019 and 2018 is as follows (in thousands):



	Three Months Ended March 31,
	2019		2018
Time-based restricted stock	$	1,406	$	1,888
Time-based restricted stock units	2,311		1,655
Performance-based restricted stock awards ⁽¹⁾	1,193		1,526
Performance-based restricted stock units	412		—
Total stock-based compensation	$	5,322	$	5,069


(1)	Includes stock-based compensation expense related to historical PSUs that were converted to PSAs.

Stock-based compensation is included in General and administrative expenses in the Company’s condensed consolidated statements of operations included within this Quarterly Report. There was approximately $39.7 million of unamortized compensation expense relating to outstanding RSAs, RSUs, PSAs and PSUs at March 31, 2019. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

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The following table summarizes the Company’s stock-based compensation award activity for the three months ended March 31, 2019:



	Time-Based Restricted Stock (RSAs)			Time-Based Restricted Stock Units (RSUs)			Performance-Based Restricted Stock Awards (PSAs)			Performance-Based Restricted Stock Units (PSUs)
Outstanding at January 1, 2019	715,852			723,354			1,338,439			—
Granted ⁽¹⁾	—			884,151			—			376,166
Vested	(250,865		)	(278,475		)	(467,401		)	—
Forfeited	(10,395		)	(33,401		)	(34,817		)	—
Outstanding at March 31, 2019	454,592			1,295,629			836,221			376,166

(1) Weighted average grant date fair value	$	—		$	17.89		$	—		$	24.05

NOTE 12. INCOME TAXES

The Company is a corporation and is subject to U.S. federal income tax and the Texas Margins Tax.

The Company’s effective combined U.S. federal and state income tax rate for the three months ended March 31, 2019 and 2018 was 21.8% and 18.1%, respectively. During the three months ended March 31, 2019 and 2018, the Company recognized an income tax benefit of $7.8 million and income tax expense of $23.3 million, respectively. Total income tax expense for the three months ended March 31, 2019 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% due to the impact of net income attributable to noncontrolling ownership interests, the change in valuation allowance and the impact of state income taxes.

The net effect of the exchange of PE Units and Class B common stock for Class A common stock during the three months ended March 31, 2019 was a decrease in deferred tax liability of $2.4 million.

Tax Receivable Agreement

In connection with the IPO, on May 29, 2014, the Company entered into a Tax Receivable Agreement (the “TRA”) with Parsley LLC and certain PE Unit Holders prior to the IPO (each such person, a “TRA Holder”), including certain executive officers. The TRA generally provides for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of (i) any tax basis increases resulting from the contribution in connection with the IPO by such TRA Holder of all or a portion of its PE Units to the Company in exchange for shares of Class A common stock, (ii) the tax basis increases resulting from the exchange by such TRA Holder of PE Units for shares of Class A common stock or, if either the Company or Parsley LLC so elects, cash, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRA. The term of the TRA commenced on May 29, 2014, and continues until all such tax benefits have been utilized or expired, unless the Company exercises its right to terminate the TRA. If the Company elects to terminate the TRA early, it would be required to make an immediate payment equal to the present value of the hypothetical future tax benefits that could be paid under the TRA (based upon certain assumptions and deemed events set forth in the TRA). In addition, payments due under the TRA will be similarly accelerated following certain mergers or other changes of control.

The actual amount and timing of payments to be made under the TRA will depend on a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers and the portion of the Company’s payments under the TRA constituting imputed interest. As of March 31, 2019, there have been no payments associated with the TRA.

As a result of the exchange of PE Units by a TRA Holder during the three months ended March 31, 2019, the Company recorded additional deferred tax assets of $3.5 million. The amount payable pursuant to the TRA increased by $3.0 million, which is 85% of the deferred tax asset, and additional paid in capital increased by $0.5 million.

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As of March 31, 2019 and December 31, 2018, the Company had recorded a TRA liability of $71.1 million and $68.1 million, respectively, for the estimated payments that will be made to the TRA Holders who have exchanged shares, along with corresponding deferred tax assets of $83.6 million and $80.1 million, respectively, as a result of the increase in tax basis arising from such exchanges and the decrease in tax basis as a result of the decrease in the future statutory tax rate.

NOTE 13. COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect, individually or in the aggregate, on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future results of operations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then-current status of the matters.

Environmental Obligations

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed as incurred. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.

Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both March 31, 2019 and December 31, 2018, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Contractual Obligations

The Company had no material changes in its contractual commitments and obligations from amounts listed under Note 13—Commitments and Contingencies to the consolidated financial statements included in the Annual Report.

NOTE 14. RELATED PARTY TRANSACTIONS

Well Operations

During each of the three months ended March 31, 2019 and 2018, certain of the Company’s directors, officers, their immediate family members, and entities affiliated or controlled by such parties (“Related Party Working Interest Owners”) owned non-operated working interests in certain of the oil and natural gas properties that the Company operates. The revenues disbursed to such Related Party Working Interest Owners totaled $0.5 million for each of the three months ended March 31, 2019 and 2018.

As a result of this ownership, from time to time, the Company will be in a net receivable or net payable position with these individuals and entities. The Company does not consider any net receivables from these parties to be uncollectible.

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Spraberry Production Services, LLC

As discussed in Note 2—Summary of Accounting Policies, the Company owns a 42.5% interest in SPS. The Company accounts for this investment using the equity method. Using the equity method of accounting results in transactions between the Company and SPS and its subsidiaries being accounted for as related party transactions. During the three months ended March 31, 2019 and 2018, the Company incurred charges totaling $1.5 million and $4.0 million, respectively, for services performed by SPS for the Company’s well operations and drilling activities.

Lone Star Well Service, LLC

The Company makes purchases of equipment used in its drilling operations from Lone Star Well Service, LLC (“Lone Star”), which is controlled by SPS. During the three months ended March 31, 2018, the Company incurred charges totaling $2.6 million for services performed by Lone Star for the Company’s well operations and drilling activities. The Company incurred no such charges during the three months ended March 31, 2019.

Exchange Right

In accordance with the terms of the Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange (the “Exchange Right”) their PE Units (and a corresponding number of shares of the Class B common stock) for shares of Class A common stock at an exchange ratio of one share of Class A common stock for each PE Unit (and a corresponding share of Class B common stock) exchanged (subject to conversion rate adjustments for stock splits, stock dividends and reclassifications) or, if the Company or Parsley LLC so elects, cash. As a PE Unit Holder exchanges its PE Units, the Company’s interest in Parsley LLC will be correspondingly increased. Refer to Note 10—Equity—Noncontrolling Interest for additional discussion.

During the three months ended March 31, 2019, an officer of the Company elected to exchange 420,000 PE Units (and a corresponding number of shares of Class B common stock) for 420,000 shares of Class A common stock. The Company exercised its call right under the Parsley LLC Agreement and elected to issue Class A common stock to the exchanging PE Unit Holder in satisfaction of such individual’s election notice.

NOTE 15. SIGNIFICANT CUSTOMERS

For the three months ended March 31, 2019 and 2018, the following customers accounted for more than 10% of the Company’s revenue:



	Three Months Ended March 31,
	2019	2018
Shell Trading (US) Company	54%	54%
Lion Oil, Inc.	28%	17%
Targa Pipeline Mid-Continent, LLC	11%	11%

If a significant customer decided to stop purchasing oil and natural gas from the Company, the Company’s revenue could decline and the Company’s operating results and financial condition could be harmed. While the Company believes that the Company could procure substitute or additional customers to offset the loss of one or more of the Company’s current significant customers, there is no assurance that the Company would be successful in doing so on terms acceptable to the Company or at all.

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NOTE 16. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:



Level 1:		Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Level 2:		Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.
Level 3:		Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. These assets and liabilities can include inventory, assets and liabilities acquired in a business combination or exchanged in non-monetary transactions, proved and unproved oil and natural gas properties, asset retirement obligations and other long-lived assets that are written down to fair value when they are impaired.

The Company periodically reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable (e.g., if there was a sustained decline in commodity prices or the productivity of the Company’s wells). The Company reviews its oil and natural gas properties by field. An impairment loss is recognized if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of a particular asset, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of such asset.

Unproved oil and natural gas properties are assessed periodically for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales, remaining lease terms and the expiration of all or a portion of such projects. The Company’s periodic assessment also considers its ability to prioritize expenditures to drill leases and to make payments to extend the lease term as well as its ability to enter into exchange transactions that allow for higher concentrations of ownership and development. The Company recognizes leasehold abandonment expense for unproved properties at the time when the lease term has expired or sooner based on management’s periodic estimates. Leasehold abandonment and impairment of unproved oil and natural gas properties is recorded in Exploration and abandonment costs in the Company’s consolidated statements of operations. During the three months ended March 31, 2019 and 2018, the Company recognized leasehold abandonment and impairment charges of $22.2 million and $5.2 million.

Proved Oil and Natural Gas Properties. During each of the three months ended March 31, 2019 and 2018, the Company did not recognize impairment charges, as the carrying amount of the assets exceeded the undiscounted future cash flows of the assets.

The Company calculates the estimated fair values using a discounted future cash flow model. Management’s assumptions associated with the calculation of discounted future cash flows include commodity prices based on NYMEX futures price strips (Level 1), as well as Level 3 assumptions including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes and (v) estimated reserves.

It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future, resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and (iv) results of future drilling activities.

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Financial Assets and Liabilities Measured at Fair Value

Commodity derivative contracts are marked-to-market each quarter and are thus stated at fair value in the accompanying condensed consolidated balance sheets and in Note 4—Derivative Financial Instruments. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements because they are calculated using industry standard models using 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 assets and liabilities according to their fair value hierarchy as of the reporting dates indicated (in thousands):



	March 31, 2019
	Level 1		Level 2			Level 3		Total
Assets:
Commodity derivative instruments⁽¹⁾	$	—	$	109,628		$	—	$	109,628
Total assets	$	—	$	109,628		$	—	$	109,628

Liabilities:
Commodity derivative instruments⁽¹⁾	$	—	$	(167,996	)	$	—	$	(167,996	)
Total liabilities	$	—	$	(167,996	)	$	—	$	(167,996	)
Net liability	$	—	$	(58,368	)	$	—	$	(58,368	)



	December 31, 2018
	Level 1		Level 2			Level 3		Total
Assets:
Commodity derivative instruments⁽¹⁾	$	—	$	211,421		$	—	$	211,421
Total assets	$	—	$	211,421		$	—	$	211,421

Liabilities:
Commodity derivative instruments⁽¹⁾	$	—	$	(168,963	)	$	—	$	(168,963	)
Total liabilities	$	—	$	(168,963	)	$	—	$	(168,963	)
Net asset	$	—	$	42,458		$	—	$	42,458



(1)	Includes deferred premiums to be settled upon the expiration of the contract.

Financial Instruments Not Carried at Fair Value

The following table provides the fair value of financial instruments that are not recorded at fair value in the condensed consolidated balance sheets (in thousands):



	March 31, 2019		December 31, 2018
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Long-term debt:
6.250% senior unsecured notes due 2024	400,000	413,748	400,000	394,144
5.375% senior unsecured notes due 2025	650,000	643,955	650,000	605,885
5.250% senior unsecured notes due 2025	450,000	446,130	450,000	424,980
5.625% senior unsecured notes due 2027	700,000	696,241	700,000	636,041
Revolving Credit Agreement	—	—	—	—

The fair values of the Notes were determined using the March 31, 2019 quoted market price, a Level 1 classification in the fair value hierarchy. The book value of the Revolving Credit Agreement approximates its fair value as the interest rate is variable. As of March 31, 2019, there are no indicators for change in the Company’s market spread.

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NOTE 17. SUBSEQUENT EVENTS

The Company has evaluated subsequent events through the date these financial statements were issued. The Company determined there were no events, other than as described below, that required disclosure or recognition in these financial statements.

Seventh Amendment to Revolving Credit Facility

On April 23, 2019, the Company, Parsley LLC, each of the guarantors thereto, Wells Fargo Bank, National Association, as administrative agent, and the other lenders party thereto, entered into the Seventh Amendment to the Revolving Credit Agreement. The Seventh Amendment, among other things, modified the terms of the Revolving Credit Agreement to (i) increase the borrowing base under the Revolving Credit Agreement from $2.3 billion to $2.7 billion (although the aggregate elected commitments of the lenders under the Revolving Credit Agreement remained at $1.0 billion), (ii) increase the Aggregate Maximum Credit Amounts (as defined in the Revolving Credit Agreement) from $2.5 billion to $5.0 billion, (iii) reduce the minimum title coverage requirement from 85% to 80% of the total value of each of (a) Parsley LLC’s and its restricted subsidiaries’ proved oil and gas properties and (b) Parsley LLC’s and its restricted subsidiaries’ proved, developed and producing reserves, in each case, as evaluated in the most recent reserve report, (iv) provide additional flexibility, subject to certain conditions, to redeem any senior notes or permitted refinancing debt and to make restricted payments, (v) provide additional flexibility, subject to certain conditions, to incur any senior notes or permitted refinancing debt in a principal amount in excess of the aggregate principal amount of senior notes or refinanced debt refinanced with such permitted refinanced debt without a reduction in the borrowing base; (vi) provide enhanced flexibility, subject to certain conditions, to make investments in and dispose of certain midstream assets; (vii) remove certain affirmative covenants; and (viii) provide, subject to certain conditions, for additional cash netting in determining Parsley LLC’s and its subsidiaries’ compliance with the consolidated leverage ratio financial covenant under the Revolving Credit Agreement.

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

The following discussion and analysis should be read in conjunction with the accompanying financial statements and related notes. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed above in “Cautionary Note Regarding Forward-Looking Statements” and in our Annual Report on Form 10-K for the year ended December 31, 2018 (the “Annual Report”) under the heading “Item 1A. Risk Factors,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

Parsley Energy, Inc. (either individually or together with its subsidiaries, as the context requires, “we,” “us,” “our” or the “Company”) is an independent oil and natural gas company focused on the acquisition, development, exploration and production of unconventional oil and natural gas properties in the Permian Basin. The Permian Basin is located in west Texas and southeastern New Mexico and is characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons, extensive production histories, long-lived reserves and historically high drilling success rates. Our properties are located in two sub areas of the Permian Basin, the Midland Basin and the Delaware Basin, where, given the associated returns, we focus predominantly on horizontal development drilling.

As a holding company and the sole managing member of Parsley Energy, LLC (“Parsley LLC”), (i) our sole material asset consists of 280,567,240 PE Units as of March 31, 2019, (ii) we are responsible for all operational, management and administrative decisions of Parsley LLC, and (iii) we consolidate the financial results of Parsley LLC and its subsidiaries.

Our Properties

At March 31, 2019, we held 259,047 gross (193,645 net) acres. Our identified horizontal drilling locations are located in Upton, Reagan, Midland, Howard, Martin and Glasscock Counties, Texas, in the Midland Basin, and Pecos and Reeves Counties, Texas, in the Delaware Basin.

As of March 31, 2019, we operated the following wells:



	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	906	723.1	389	362.5	1,295	1,085.6
Delaware Basin	13	12.5	98	93.0	111	105.5
Total	919	735.6	487	455.5	1,406	1,191.1

As of March 31, 2019, we held an interest in 1,849 gross (1,252.4 net) wells, including wells that we do not operate.

From the commencement of our horizontal drilling program in 2013 through March 31, 2019, we have placed on production 382 gross (341.4 net) horizontal wells in the Midland Basin and 79 gross (74 net) horizontal wells in the Delaware Basin. The table below summarizes the horizontal wells placed on production during the three months ended March 31, 2019:

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How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:


•	production volumes;


•	realized prices on the sale of oil, natural gas, and NGLs, including the effect of our commodity derivative contracts;


•	lease operating expenses;


•	capital expenditures;


•	returns on capital invested; and


•	certain unit costs.

Sources of Our Revenues

Our production revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing, and do not include the effects of derivatives. Our production revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

The following table presents the breakdown of our production revenues for the periods indicated:



	Three Months Ended March 31,
	2019		2018
Oil sales	87	%	86	%
Natural gas sales	3	%	4	%
Natural gas liquids sales	10	%	10	%

Other revenues are not material and include fees charged by certain of our subsidiaries. During each of the three months ended March 31, 2019 and 2018, other revenues included water, easement and other surface use fees charged by Parsley Minerals, LLC to third parties, as well as salt water disposal and gathering system income. During the three months ended March 31, 2018, other revenues also included drilling service fees charged by Pacesetter Drilling, LLC (“Pacesetter”) to third parties for drilling services.

Production Volumes

The following table presents production volumes for our properties for the three months ended March 31, 2019 and 2018:



	Three Months Ended March 31,
	2019	2018
Oil (MBbls)	7,102	5,341
Natural gas (MMcf)	10,488	8,556
Natural gas liquids (MBbls)	2,436	1,643
Total (MBoe)	11,286	8,410
Average net production (Boe/d)	125,400	93,444

Production Volumes Directly Impact Our Results of Operations

As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through the development of our properties as well as through acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions.

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Realized Prices on the Sale of Oil, Natural Gas and NGLs

Historically, oil, natural gas and NGLs prices have been extremely volatile, and we expect this volatility to continue. Because our production consists primarily of oil, our production revenues are more sensitive to fluctuations in the price of oil than they are to fluctuations in the price of natural gas or NGLs.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, we enter into derivative arrangements for a portion of our production, with an emphasis on our oil production. By removing a portion of price volatility associated with our oil production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil prices on our cash flow from operations for the relevant periods. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our oil, natural gas or NGLs production. See Note 4—Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this Quarterly Report for details regarding volumes and terms of our derivative instruments as of March 31, 2019.

We will have recognized the following cumulative losses in the line item Loss on derivatives on our condensed consolidated statements of operations from net premiums paid or deferred on options that will settle during the following periods (in thousands):



Q2 2019	$	(10,232	)
Q3 2019	(14,486		)
Q4 2019	(14,486		)
Q1 2020	(6,009		)
Q2 2020	(6,009		)
Q3 2020	(825		)
Q4 2020	(825		)
Total	$	(52,872	)

Recent Transactions

Seventh Amendment to Revolving Credit Facility

On April 23, 2019, the Company, Parsley LLC, each of the guarantors thereto, Wells Fargo Bank, National Association, as administrative agent, and the other lenders party thereto, entered into the Seventh Amendment (the “Seventh Amendment”) to our revolving credit agreement (the “Revolving Credit Agreement”). The Seventh Amendment, among other things, modified the terms of the Revolving Credit Agreement to (i) increase the borrowing base under the Revolving Credit Agreement from $2.3 billion to $2.7 billion (although the aggregate elected commitments of the lenders under the Revolving Credit Agreement remained at $1.0 billion), (ii) increase the Aggregate Maximum Credit Amounts (as defined in the Revolving Credit Agreement) from $2.5 billion to $5.0 billion, (iii) reduce the minimum title coverage requirement from 85% to 80% of the total value of each of (a) Parsley LLC’s and its restricted subsidiaries’ proved oil and gas properties and (b) Parsley LLC’s and its restricted subsidiaries’ proved, developed and producing reserves, in each case, as evaluated in the most recent reserve report, (iv) provide additional flexibility, subject to certain conditions, to redeem any senior notes or permitted refinancing debt and to make restricted payments, (v) provide additional flexibility, subject to certain conditions, to incur any senior notes or permitted refinancing debt in a principal amount in excess of the aggregate principal amount of senior notes or refinanced debt refinanced with such permitted refinanced debt without a reduction in the borrowing base; (vi) provide enhanced flexibility, subject to certain conditions, to make investments in and dispose of certain midstream assets; (vii) remove certain affirmative covenants; and (viii) provide, subject to certain conditions, for additional cash netting in determining Parsley LLC’s and its subsidiaries’ compliance with the consolidated leverage ratio financial covenant under the Revolving Credit Agreement.

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Impairment of Proved Oil and Natural Gas Properties

Proved oil and natural gas properties are reviewed for impairment periodically or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare the undiscounted cash flows to the carrying amount of the oil and natural gas properties, on a field by field basis, to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to estimated fair value.

Given the volatility of commodity prices in recent years and their impact on our estimated future cash flows, we periodically review our proved oil and natural gas properties for impairment. During each of the three months ended March 31, 2019 and 2018, we did not recognize an impairment of our proved oil and natural gas properties. At March 31, 2019, in our significant fields that comprise 100% of our carrying value, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and natural gas properties by an average of 81% per field and, individually, by a minimum of 70%.

The key assumptions used to determine the undiscounted future cash flows include, but are not limited to, future commodity prices, price differentials, future production estimates, estimated future capital expenditures and estimated future operating expenses. All inputs in the undiscounted future cash flow estimate, except commodity price estimates, remained relatively consistent from March 31, 2018 to March 31, 2019. We evaluate future commodity pricing for oil and NGLs based on five-year WTI futures prices, which remained relatively consistent from March 31, 2018 to March 31, 2019, and future commodity pricing for natural gas based on five-year Henry Hub futures prices, which decreased from March 31, 2018 to March 31, 2019. The increase in value of undiscounted cash flows from March 31, 2018 to March 31, 2019 is due to the addition of both proved developed and proved undeveloped reserves through our continued drilling and completion of previously unproved oil and natural gas properties and certain acquisitions.

As part of our period end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs and operating expense assumptions. There is a significant degree of uncertainty with respect to the assumptions used to estimate future undiscounted cash flows due to, but not limited to, the risk factors referred to in “Item 1A. Risk Factors” included in the Annual Report.

Any decrease in pricing, negative change in price differentials or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties. A decrease of 10% in estimated future pricing of oil and natural gas commodities as of March 31, 2019, however, would not have resulted in an impairment of our proved oil and natural gas properties.

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Capital Expenditures

Our drilling, completions and infrastructure activities are capital intensive and require us to make substantial capital expenditures, which vary from year to year. For further information about our capital expenditures, see “—Capital Requirements and Sources of Liquidity.”

The following table sets forth our capital expenditures for drilling, completions and infrastructure for the periods indicated (in thousands):



	Three Months Ended March 31,
	2019		2018
Capital expenditures	$	406,304	$	424,086

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Results of Operations

Revenues

The following table provides the components of our production revenues for the periods indicated, as well as each period’s respective average prices and production volumes:



	Three Months Ended March 31,
	2019		2018
Production revenues (in thousands):
Oil sales	$	368,126	$	331,103
Natural gas sales	14,452		17,424
Natural gas liquids sales	43,785		40,620
Total revenues	$	426,363	$	389,147

Average realized prices ⁽¹⁾:
Oil, without realized derivatives (per Bbls)	$	51.83	$	61.99
Oil, with realized derivatives (per Bbls)	49.40		58.32
Natural gas, without realized derivatives (per Mcf)	1.38		2.04
Natural gas, with realized derivatives (per Mcf)	1.33		2.06
Natural gas liquids (per Bbls)	17.97		24.72
Average price per Boe, without realized derivatives	37.78		46.27
Average price per Boe, with realized derivatives	36.20		43.97

Production:
Oil (MBbls)	7,102		5,341
Natural gas (MMcf)	10,488		8,556
Natural gas liquids (MBbls)	2,436		1,643
Total (MBoe)	11,286		8,410

Average daily production volume:
Oil (Bbls)	78,911		59,344
Natural gas (Mcf)	116,533		95,067
Natural gas liquids (Bbls)	27,067		18,256
Total (Boe)	125,400		93,444



(1)	Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains and losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period.

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The table below shows, for the periods indicated, our average realized oil price as a percentage of the average NYMEX oil price, our average realized natural gas price as a percentage of the average NYMEX gas price, and our average realized NGLs price as a percentage of the average NYMEX oil price. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil, natural gas and NGLs revenues. Realized oil, natural gas and NGLs prices are the actual prices realized at the wellhead, adjusted for quality, transportation fees and costs, differentials, marketing premiums or deductions and other factors that affect the price received at the wellhead.



	Three Months Ended March 31,
	2019			2018
Average realized oil price ($/Bbl)	$	51.83		$	61.99
Average NYMEX ($/Bbl)	$	54.74		$	62.89
Differential to NYMEX	$	(2.91	)	$	(0.90	)
Average realized oil price as a percentage of average NYMEX oil price	95		%	99		%
Average realized natural gas price ($/Mcf)	$	1.38		$	2.04
Average NYMEX ($/Mcf)	$	2.88		$	2.85
Differential to NYMEX	$	(1.50	)	$	(0.81	)
Average realized natural gas price as a percentage of average NYMEX gas price	48		%	72		%
Average realized NGLs price ($/Bbl)	$	17.97		$	24.72
Average NYMEX ($/Bbl)	$	54.74		$	62.89
Differential to NYMEX	$	(36.77	)	$	(38.17	)
Average realized NGLs price as a percentage of average NYMEX oil price	33		%	39		%

Oil, natural gas and NGLs revenues. Our oil, natural gas and NGLs revenues increased by $37.3 million, or 10%, to $426.4 million for the three months ended March 31, 2019 from $389.1 million for the three months ended March 31, 2018.

As shown in the following tables, from the three months ended March 31, 2018 to the three months ended March 31, 2019, the net dollar effect of the decrease in oil, natural gas and NGLs prices was $95.5 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs was $132.7 million.



	Change in prices			Three months ended March 31, 2019 Production volumes	Total net dollar effect of change
Effect of change in price:				(in thousands)	(in thousands)
Oil (per Bbls)	$	(10.16	)	7,102	$	(72,146	)
Natural gas (per Mcf)	(0.66		)	10,488	(6,907		)
Natural gas liquids (per Bbls)	(6.75		)	2,436	(16,440		)
Total revenues due to change in price					$	(95,493	)



	Change in production volumes	Three months ended March 31, 2018 Average prices		Total net dollar effect of change
Effect of change in production volumes:	(in thousands)			(in thousands)
Oil (MBbls)	1,761	$	61.99	$	109,169
Natural gas (MMcf)	1,932	2.04		3,935
Natural gas liquids (MBbls)	793	24.72		19,605
Total revenues due to change in production volumes				$	132,709

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Operating expenses

The following table summarizes our expenses for the periods indicated:



	Three Months Ended March 31,
	2019			2018
Operating expenses (in thousands):
Lease operating expenses	$	41,172		$	28,832
Transportation and processing costs	8,257			6,267
Production and ad valorem taxes	27,407			24,186
Depreciation, depletion and amortization	173,723			121,199
General and administrative expenses ⁽¹⁾	38,037			34,995
Exploration and abandonment costs	22,994			5,411
Acquisition costs	—			4
Accretion of asset retirement obligations	345			354
Loss on sale of property	—			111
Other operating (income) expenses	(811		)	2,175
Total operating expenses	$	311,124		$	223,534

Expense per Boe:
Lease operating expenses	$	3.65		$	3.43
Transportation and processing costs	0.73			0.75
Production and ad valorem taxes	2.43			2.88
Depreciation, depletion and amortization	15.39			14.41
General and administrative expenses	3.37			4.16
Exploration and abandonment costs	2.04			0.64
Acquisition costs	—			—
Accretion of asset retirement obligations	0.03			0.04
Loss on sale of property	—			0.01
Other operating (income) expenses	(0.07		)	0.26
Total operating expenses per Boe	$	27.57		$	26.58


(1)	General and administrative expenses include stock-based compensation expense of $5.3 million and $5.1 million for the three months ended March 31, 2019 and 2018, respectively.

Lease operating expenses. Lease operating expenses were $41.2 million and $28.8 million for the three months ended March 31, 2019 and 2018, respectively. The increase is primarily due to the significant increase in in our asset base, including both our operated and non-operated wells.

On a per Boe basis, lease operating expenses increased $0.22 per Boe, or 6%, to $3.65 for the three months ended March 31, 2019 from $3.43 for the three months ended March 31, 2018. The increase in lease operating expenses per Boe is primarily attributable to increased compression and other rental charges, partially offset by a 34% increase in production period over period.

Transportation and processing costs. Transportation and processing costs, which represent third-party costs related to certain of our natural gas and NGLs marketing and processing agreements, were $8.3 million and $6.3 million for the three months ended March 31, 2019 and 2018, respectively. On a per Boe basis, transportation and processing costs were $0.73 and $0.75 per Boe for the three months ended March 31, 2019 and 2018, respectively.

Production and ad valorem taxes. Production and ad valorem taxes were $27.4 million and $24.2 million for the three months ended March 31, 2019 and 2018, respectively. On a per Boe basis, production and ad valorem taxes decreased from $2.88 per Boe for the three months ended March 31, 2018 to $2.43 per Boe for the three months ended March 31, 2019.

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Overall, for the three months ended March 31, 2019, compared to the same period in 2018, production taxes increased by approximately $1.9 million, reflecting increased production volumes. Ad valorem taxes increased $1.3 million over the same period, reflecting higher property valuation assessments by local taxing authorities.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $173.7 million and $121.2 million for the three months ended March 31, 2019 and 2018, respectively.

The increase is largely attributable to development activity that resulted in an increase in costs subject to depletion as of March 31, 2019 as compared to March 31, 2018 and a 34% increase in production during the three months ended March 31, 2019, respectively, as compared to the same period in 2018. These increases were partially offset by a 19% increase in total proved reserves and a 42% increase in proved developed reserves as of March 31, 2019, as compared to March 31, 2018.

On a per Boe basis, DD&A expense increased to $15.39 for the three months ended March 31, 2019 from $14.41 during the three months ended March 31, 2018, primarily due to the increase in production volumes and reserves discussed above.

General and administrative expenses. General and administrative expenses were $38.0 million and $35.0 million during the three months ended March 31, 2019 and 2018, respectively. The increase is primarily due to higher payroll and office rent expenses associated with the hiring of additional employees during 2018 to manage our growing asset base and increased production. General and administrative expenses per Boe were $3.37 and $4.16 during the three months ended March 31, 2019 and 2018, respectively. The decrease is a result of production volume growth outpacing general and administrative expenses growth.

Exploration and abandonment costs. The following table provides a breakdown of exploration and abandonment costs incurred for the periods indicated (in thousands):



	Three Months Ended March 31,
	2019		2018
Leasehold abandonments and impairments	$	22,189	$	5,179
Geological and geophysical costs	797		192
Other	8		40
Total exploration and abandonment costs	$	22,994	$	5,411

During the three months ended March 31, 2019 and 2018, we recognized leasehold abandonment and impairment charges of approximately $22.2 million and $5.2 million, respectively, which primarily relate to the release or abandonment of non-core acreage during the period.

During the three months ended March 31, 2019 and 2018, we incurred geological and geophysical expenses of $0.8 million and $0.2 million, respectively. Our geological and geophysical expenses consist of the costs of acquiring and processing seismic data, geophysical data and core analysis, primarily relating to geoscientific analysis of our acreage.

We recognized other exploration costs of $8.0 thousand and $40.0 thousand during the three months ended March 31, 2019 and 2018, respectively, which includes research and other similar costs.

Acquisition costs. During the three months ended March 31, 2018, we incurred $4.0 thousand of acquisition costs which include non-recurring legal and other due diligence fees associated with certain acquisitions. There were no such costs incurred during the three months ended March 31, 2019.

Loss on sale of property. We recognized a loss on the sale of property of $0.1 million during the three months ended March 31, 2018, as discussed in Note 6—Acquisitions and Divestitures to our condensed consolidated financial statements included elsewhere in this Quarterly Report. There were no such costs incurred during the three months ended March 31, 2019.

Other operating (income) expenses. During the three months ended March 31, 2019, other operating (income) expense included a credit associated with idle charges of $0.8 million. During the three months ended March 31, 2018, other operating expense of $2.2 million was primarily comprised of costs incurred during the normal course of business of our majority-owned subsidiary, Pacesetter. There were no such costs incurred during the three months ended March 31, 2019 as Pacesetter completed the sale of all of its physical assets during 2018.

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Other income (expense)

The following table summarizes our other income and expenses for the periods indicated:



	Three Months Ended March 31,
	2019			2018
Other income (expense) (in thousands):
Interest expense, net	$	(33,002	)	$	(31,968	)
Loss on derivatives	(119,687		)	(10,793		)
Change in TRA liability	—			(82		)
Interest income	291			2,123
Other income	58			301
Total other expense, net	$	(152,340	)	$	(40,419	)

Interest expense, net. Interest expense, net for the three months ended March 31, 2019 and 2018 was $33.0 million and $32.0 million, respectively.

Loss on derivatives. We recognized loss on derivatives of $119.7 million and $10.8 million during the three months ended March 31, 2019 and 2018, respectively, primarily as a result of higher commodity prices, which lowered the value of our derivative portfolio.

Change in TRA liability. During the three months ended March 31, 2018, we recorded a $0.1 million expense associated with an increase in the TRA liability resulting from the reversal of the valuation allowance recorded during 2017. We incurred no such costs during the three months ended March 31, 2019.

Interest income. Interest income was $0.3 million and $2.1 million during the three months ended March 31, 2019 and 2018, respectively. The change is a result of decreased interest income, including amortization, associated with our previous held-to-maturity securities.

Other income. Other income was $0.1 million and $0.3 million for the three months ended March 31, 2019 and 2018, respectively. The decrease in other income for the three months ended March 31, 2019, as compared to the same respective period in 2018, is attributable to a decrease in income from our equity investment in Spraberry Production Services, LLC, offset by increases in other miscellaneous items.

Income Tax Benefit (Expense)

During the three months ended March 31, 2019 and 2018, we recognized income tax benefit of $7.8 million and income tax expense of $23.3 million, respectively. These changes were attributable to the changes in our results of operations, discussed above, as well as the impact of net income attributable to noncontrolling ownership interests, change in valuation allowance and state income taxes.

Capital Requirements and Sources of Liquidity

The following table sets forth our capital expenditures for drilling, completions and infrastructure for the periods indicated (in thousands):



	Three Months Ended March 31,
	2019		2018
Capital expenditures	$	406,304	$	424,086

Our 2019 budget for capital development expenditures is approximately $1,350.0 million to $1,550.0 million, approximately 85% of which is expected to be used for drilling and completions and approximately 15% of which is expected to be used for infrastructure and other expenditures. We expect approximately 30% to 35% of the total budget to be associated with drilling and completions for proved undeveloped reserves as of December 31, 2018. Our capital budget excludes any amounts that may be paid for acquisitions. The amount and timing of 2019 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2019 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural

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gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners.

Based upon current oil and natural gas price expectations for fiscal year 2019, we believe that our cash on hand, cash flow from operations and borrowings under our Revolving Credit Agreement will be sufficient to fund our operations through 2019. As of March 31, 2019, our liquidity was as follows (in millions):



Cash and cash equivalents	$	10.4
Revolving Credit Agreement availability	991.3
Liquidity	$	1,001.7

Future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop our properties. For example, we expect a portion of our future capital expenditures to be financed with cash flows from operations derived from wells drilled in drilling locations not associated with proved reserves on our December 31, 2018 reserve report. The failure to achieve anticipated production and cash flows from operations from such wells could result in a reduction in future capital spending. Further, our capital expenditure budget for 2019 does not allocate any amounts for acquisitions of oil and natural gas properties. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt or equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Cash Flows

The following table summarizes our cash flows for the periods indicated (in thousands):



	Three Months Ended March 31,
	2019			2018
Net cash provided by operating activities	$	213,059		$	226,955
Net cash used in investing activities	(359,307		)	(423,191		)
Net cash used in financing activities	(6,588		)	(7,191		)

Cash flows provided by operating activities. Net cash provided by operating activities was approximately $213.1 million and $227.0 million for the three months ended March 31, 2019 and 2018, respectively. Net cash provided by operating activities decreased primarily due to a $17.4 million increase in cash based operating expenses during the three months ended March 31, 2019 as compared to the three months ended March 31, 2018. Cash based operating expenses include lease operating expenses, transportation and processing costs, production and ad valorem taxes, cash general and administrative expenses and acquisition costs.

Cash flows used in investing activities. Net cash used in investing activities was approximately $359.3 million and $423.2 million for the three months ended March 31, 2019 and 2018, respectively. The reduction in the amount of cash used in investing activities was due primarily to a $58.4 million decrease in development costs related to our oil and natural gas properties and a $13.6 million decrease in acquisition costs. Please refer to Note 6—Acquisitions and Divestitures to our condensed consolidated financial statements included elsewhere in this Quarterly Report for additional discussion related to acquisitions.

Cash flows used in financing activities. Net cash used in financing activities was $6.6 million and net cash provided by financing activities was $7.2 million for the three months ended March 31, 2019 and 2018, respectively. Net cash used by financing activities decreased by $0.6 million during the three months ended March 31, 2019 as a result of decreased amounts associated with the vesting of restricted stock units.

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Capital Sources

Revolving Credit Agreement. See Note 8—Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report for information regarding our Revolving Credit Agreement.

6.250% Senior Unsecured Notes due 2024. See Note 8—Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report for information regarding our 6.250% senior unsecured notes due 2024.

5.375% Senior Unsecured Notes due 2025. See Note 8—Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report for information regarding our 5.375% senior unsecured notes due 2025.

5.250% Senior Unsecured Notes due 2025. See Note 8—Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report for information regarding our 5.250% senior unsecured notes due 2025.

5.625% Senior Unsecured Notes due 2027. See Note 8—Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report for information regarding our 5.625% senior unsecured notes due 2027.

Derivative activity. We plan to continue our practice of entering into hedging arrangements to (i) reduce the impact of commodity price volatility on our cash flow from operations and (ii) support our annual capital budgeting and expenditure plans. Under this strategy, we intend to continue our historical practice of entering into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering a portion of our projected oil production.

Working Capital

Our working capital totaled ($423.8) million and ($108.2) million at March 31, 2019 and December 31, 2018, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents totaled $10.4 million and $163.2 million at March 31, 2019 and December 31, 2018, respectively. The $152.8 million decrease in cash and cash equivalents is primarily attributable to the development of our oil and natural gas properties, as described in “—Factors Affecting the Comparability of Our Financial Condition and Results of Operations—Capital Expenditures.” Due to the costs incurred related to our drilling program, we may incur additional working capital deficits in the future. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will continue to be the largest variables affecting our working capital.

Contractual Obligations

We had no material changes in our contractual commitments and obligations during the three months ended March 31, 2019 from the amounts listed under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” in the Annual Report.

Critical Accounting Policies and Estimates

There have not been any material changes during the three months ended March 31, 2019 to the methodology applied by management for critical accounting policies previously disclosed in the Annual Report. Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in the Annual Report for further description of our critical accounting policies.

Off-Balance Sheet Arrangements

As of March 31, 2019, we were party to certain transportation and sale agreements providing for the delivery of fixed and determinable quantities of oil and natural gas, which we enter into in the ordinary course of business. If production volumes are not sufficient to meet these contracted delivery commitments, we may be subject to deficiency fees unless we purchase commodities in the market to satisfy such commitments. See Note 13—Commitments and Contingencies to our condensed consolidated financial statements included elsewhere in this Quarterly Report.

We do not otherwise maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition,

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changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to our consolidated financial statements.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in the prices of the commodities we sell. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil and natural gas production. Pricing for our production has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

We enter into multiple types of commodity derivative contracts to (i) reduce the effect of price volatility on our oil and natural gas revenues and (ii) support our annual capital budgeting and expenditure plans. We plan to continue our practice of entering into such transactions at times and on terms desired to maintain a portfolio of commodity derivative contracts covering a portion of our projected oil production. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure to oil price fluctuations. For a description of our open positions at March 31, 2019, see Note 4—Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this Quarterly Report.

We do not require collateral from our counterparties for entering into derivative instruments, so in order to mitigate the credit risk associated with such derivative instruments, we typically enter into an International Swap Dealers Association Master Agreement (“ISDA Agreement”) with each of our counterparties. The ISDA Agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each derivative transaction between the counterparty and us separately, the ISDA Agreement enables the counterparty and us to aggregate all trades under such agreement and treat them as a single agreement. This arrangement is intended to benefit us in two ways: (i) default by a counterparty under a single trade can trigger rights to terminate all trades with such counterparty that are subject to the ISDA Agreement; and (ii) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.

As of March 31, 2019, the fair market value of our oil and natural gas derivative contracts was a net liability of $58.4 million, including deferred premium payables of $54.2 million. The deferred premium payable is a fixed amount and is not marked to fair market value. As of March 31, 2019, the fair market value of our oil derivative contracts was a net liability of $60.4 million. Based on our open oil derivative positions at March 31, 2019, a 10% increase in the NYMEX WTI price would increase our net oil derivative liability by approximately $74.8 million, while a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $71.1 million. As of March 31, 2019, the fair market value of our natural gas derivative contracts was a net asset of $2.0 million. Based on our open natural gas derivative positions at March 31, 2019, a 10% increase in the NYMEX Henry Hub price would increase our net natural gas derivative asset by approximately $0.4 million. Based on our open natural gas derivative positions at March 31, 2019, a 10% decrease in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately $0.6 million. Please read “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Realized Prices on the Sale of Oil, Natural Gas and NGLs.”

Counterparty Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. We plan to continue to evaluate the credit standings of our counterparties in a similar manner. The majority of our derivative contracts currently in place are with lenders under our Revolving Credit Agreement, each of whom has an investment grade rating.

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Interest Rate Risk

Our market risk exposure related to changes in interest rates relates primarily to debt obligations and the amount of interest we earn on our short-term investments. As of March 31, 2019, we had $2.2 billion of fixed-rate long-term debt outstanding with a weighted average interest rate of 5.6%. Although near term changes may impact the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss. We are exposed to interest rate risk as a result of our Revolving Credit Agreement, which requires us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. As of March 31, 2019, however, we had no outstanding borrowings under our Revolving Credit Agreement and therefore a change in interest rates as of such date would not have resulted in increased or decreased interest expense.

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Item 4. Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2019. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2019 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended March 31, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we are a party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment-related disputes. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations, or liquidity.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in the Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially and adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in the Annual Report or our other SEC filings.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth information with respect to our repurchases of shares of Class A common stock during the three months ended March 31, 2019:



Period	Total number of shares purchased ⁽¹⁾	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Approximate dollar value of shares that may yet be purchased under the plans or programs
1/1/2019 - 1/31/2019	—	$	—	—	$	—
2/1/2019 - 2/28/2019	281,592	$	18.23	—	$	—
3/1/2019 - 3/31/2019	9,724	$	18.13	—	$	—
Total	291,316	$	18.23	—	$	—



(1)	Consists of shares of Class A common stock repurchased from employees in order for the employee to satisfy tax withholding payments related to stock-based awards that vested during the period.

Item 6. Exhibits

The exhibits required to be filed by Item 6 are set forth in the Exhibit Index included below.

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EXHIBIT INDEX



Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
3.2		Amended and Restated Bylaws of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on October 30, 2018).
10.1†		First Amendment to Amended and Restated Employment, Confidentiality and Non-Competition Agreement, dated as of February 15, 2019, by and between Parsley Energy Operations, LLC and Matt Gallagher (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on February 15, 2019).
10.2†		Letter Agreement, dated as of February 15, 2019, by and between Parsley Energy, Inc. and Bryan Sheffield (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on February 15, 2019).
10.3		Third Amended and Restated Limited Liability Company Agreement of Parsley Energy, LLC, dated as of February 20, 2019 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on February 26, 2019).
10.4		Seventh Amendment to Credit Agreement, dated as of April 23, 2019, among Parsley Energy, LLC, as borrower, Parsley Energy, Inc., each of the guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent, JPMorgan Chase Bank, N.A., as syndication agent, BMO Harris Bank, N.A., as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 24, 2019).
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.



†	Management contract or compensatory plan or arrangement.



*	Filed herewith.



**	Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Quarterly Report on Form 10-Q and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act, except to the extent that the registrant specifically incorporates it by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	PARSLEY ENERGY, INC.

May 3, 2019	By:	/s/ Matt Gallagher
		Matt Gallagher
		President and Chief Executive Officer (Principal Executive Officer)


May 3, 2019	By:	/s/ Ryan Dalton
		Ryan Dalton
		Executive Vice President—Chief Financial Officer (Principal Accounting and Financial Officer)