Parsley Energy, Inc. (Form: 10-Q, Received: 08/08/2019 10:08:44)

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xbrli:shares iso4217:USD utreg:MMBTU pe:Well

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2019



☐	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

(State or other jurisdiction
of incorporation or organization)

303 Colorado Street, Suite 3000

Austin, Texas

(Address of principal executive offices)

46-4314192

(I.R.S. Employer
Identification No.)

78701

(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 ý 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 ý 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.



Large accelerated filer	ý	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. ¨

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

As of August 8, 2019, the registrant had 281,116,921 shares of Class A common stock and 35,538,145 shares of Class B common stock outstanding.

Table of Contents

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	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	49

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6.	Exhibits	51
	Signatures	53

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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)	Parsley LLC Agreement. The Limited Liability Company Agreement of Parsley LLC, dated June 11, 2013, thereafter amended and restated by the Second Amended and Restated Limited Liability Company Agreement, dated May 29, 2014, thereafter amended and restated by the Third Amended and Restated Limited Liability Company Agreement, dated February 20, 2019, thereafter amended and restated by the Fourth Amended and Restated Limited Liability Company Agreement, dated July 22, 2019, as in effect as of the applicable date.



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



(31)	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.



(32)	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).



(33)	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:

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	(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;



	(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.



(34)	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).



(35)	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.



(36)	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.



(37)	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.



(38)	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.



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



(40)	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.



(41)	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.



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



(43)	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.



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



(45)	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.

Table of Contents

PART I: FINANCIAL INFORMATION

Item 1: Financial Statements

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2019			December 31, 2018
	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	64,099		$	163,216
Accounts receivable, net of allowance for doubtful accounts:
Joint interest owners and other	30,273			39,564
Oil, natural gas and NGLs	158,917			136,209
Related parties	892			94
Short-term derivative instruments, net	134,103			191,297
Other current assets	7,420			10,332
Total current assets	395,704			540,712
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method	10,675,629			9,948,246
Accumulated depreciation, depletion and impairment	(1,647,036		)	(1,295,098		)
Total oil and natural gas properties, net	9,028,593			8,653,148
Other property, plant and equipment, net	188,144			170,739
Total property, plant and equipment, net	9,216,737			8,823,887
NONCURRENT ASSETS
Operating lease assets, net of accumulated depreciation	179,066			—
Long-term derivative instruments, net	39,750			20,124
Other noncurrent assets	6,809			6,640
Total noncurrent assets	225,625			26,764
TOTAL ASSETS	$	9,838,066		$	9,391,363

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses	$	423,145		$	364,803
Revenue and severance taxes payable	132,131			127,265
Short-term derivative instruments, net	150,427			152,330
Current operating lease liabilities	79,719			—
Other current liabilities	3,846			4,547
Total current liabilities	789,268			648,945
NONCURRENT LIABILITIES
Long-term debt	2,221,355			2,181,667
Deferred tax liability	156,159			131,523
Operating lease liability	102,479			—
Payable pursuant to tax receivable agreement	71,077			68,110
Long-term derivative instruments, net	40,485			16,633
Asset retirement obligations	26,948			24,750
Financing lease liability	2,294			—
Total noncurrent liabilities	2,620,797			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, 282,134,006 shares issued and 281,116,921 shares outstanding at June 30, 2019 and 280,827,038 shares issued and 280,205,293 shares outstanding at December 31, 2018	2,821			2,808
Class B, $0.01 par value, 125,000,000 shares authorized, 35,538,145 and 36,547,731 shares issued and outstanding at June 30, 2019 and December 31, 2018	356			366
Additional paid in capital	5,190,453			5,163,987
Retained earnings	504,517			412,646
Treasury stock, at cost, 1,017,085 shares and 621,745 shares at June 30, 2019 and December 31, 2018	(17,401		)	(11,749		)
Total stockholders' equity	5,680,746			5,568,058
Noncontrolling interests	747,255			751,677
Total equity	6,428,001			6,319,735
TOTAL LIABILITIES AND EQUITY	$	9,838,066		$	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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In thousands, except per share data)
REVENUES
Oil sales	$	458,888		$	396,325		$	827,014		$	727,428
Natural gas sales	141			12,235			14,593			29,659
Natural gas liquids sales	38,312			57,275			82,097			97,895
Other	1,200			1,953			2,508			5,547
Total revenues	498,541			467,788			926,212			860,529
OPERATING EXPENSES
Lease operating expenses	42,696			35,904			83,868			64,736
Transportation and processing costs	6,608			6,471			14,865			12,738
Production and ad valorem taxes	30,744			27,331			58,151			51,517
Depreciation, depletion and amortization	198,563			145,552			372,286			266,751
General and administrative expenses (including stock-based compensation of $4,976 and $5,363 for the three months ended June 30, 2019 and 2018 and $10,298 and $10,432 for the six months ended June 30, 2019 and 2018)	34,907			35,991			72,944			70,986
Exploration and abandonment costs	72			3,366			23,066			8,777
Acquisition costs	—			(2		)	—			2
Accretion of asset retirement obligations	353			359			698			713
Gain on sale of property	—			(5,166		)	—			(5,055		)
Restructuring and other termination costs	1,562			—			1,562			—
Other operating expenses	2,199			2,477			1,388			4,652
Total operating expenses	317,704			252,283			628,828			475,817
OPERATING INCOME	180,837			215,505			297,384			384,712
OTHER INCOME (EXPENSE)
Interest expense, net	(33,597		)	(33,758		)	(66,599		)	(65,726		)
Gain (loss) on derivatives	19,561			(9,466		)	(100,126		)	(20,259		)
Change in TRA liability	—			—			—			(82		)
Interest income	103			1,686			394			3,809
Other income	715			234			773			535
Total other expense, net	(13,218		)	(41,304		)	(165,558		)	(81,723		)
INCOME BEFORE INCOME TAXES	167,619			174,201			131,826			302,989
INCOME TAX EXPENSE	(32,625		)	(33,243		)	(24,835		)	(56,568		)
NET INCOME	134,994			140,958			106,991			246,421
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(19,059		)	(21,803		)	(15,120		)	(44,376		)
NET INCOME ATTRIBUTABLE TO PARSLEY ENERGY, INC. STOCKHOLDERS	$	115,935		$	119,155		$	91,871		$	202,045

Net income per common share:
Basic	$	0.41		$	0.44		$	0.33		$	0.76
Diluted	$	0.41		$	0.44		$	0.33		$	0.76
Weighted average common shares outstanding:
Basic	279,706			272,239			279,253			266,479
Diluted	279,768			272,846			279,363			267,043

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

Table of Contents

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 interests			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 income	—	—		—		—			—			(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
Exchange of PE Units and Class B Common Stock for Class A Common Stock	590	(590	)	6		(6		)	12,662			—			—	—			12,662			(12,662		)	—
Change in net deferred tax liability due to issuance of PE Units by Parsley LLC	—	—		—		—			(2,197		)	—			—	—			(2,197		)	—			(2,197		)
Vesting of restricted stock units	18	—		—		—			—			—			—	—			—			—			—
Repurchase of common stock	—	—		—		—			—			—			18	(343		)	(343		)	—			(343		)
Restricted stock forfeited	—	—		—		—			(676		)	—			41	—			(676		)	—			(676		)
Stock-based compensation	—	—		—		—			5,652			—			—	—			5,652			—			5,652
Net income	—	—		—		—			—			115,935			—	—			115,935			19,059			134,994
Balance at June 30, 2019	282,134	35,538		$	2,821	$	356		$	5,190,453		$	504,517		1,017	$	(17,401	)	$	5,680,746		$	747,255		$	6,428,001

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

Table of Contents

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (CONTINUED)

(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 interests			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
Exchange of PE Units and Class B Common Stock for Class A Common Stock	11,480	(11,480	)	114		(114		)	217,463			—		—	—			217,463			(217,463		)	—
Change in net deferred tax liability due to issuance of PE Units by Parsley LLC	—	—		—		—			(11,418		)	—		—	—			(11,418		)	—			(11,418		)
Issuance of restricted stock	52	—		—		—			—			—		—	—			—			—			—
Vesting of restricted stock units	24	—		1		—			(1		)	—		—	—			—			—			—
Repurchase of common stock	—	—		—		—			—			—		150	(4,406		)	(4,406		)	—			(4,406		)
Restricted stock forfeited	—	—		—		—			(205		)	—		—	—			(205		)	—			(205		)
Stock-based compensation	—	—		—		—			5,568			—		—	—			5,568			—			5,568
Net income	—	—		—		—			—			119,155		—	—			119,155			21,803			140,958
Balance at June 30, 2018	280,106	37,252		$	2,801	$	373		$	5,123,089		$	245,564	588	$	(11,606	)	$	5,360,221		$	739,926		$	6,100,147

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

Table of Contents

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2019			2018
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	106,991		$	246,421
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	372,286			266,751
Leasehold abandonments and impairments	22,189			8,323
Accretion of asset retirement obligations	698			713
Gain on sale of property	—			(5,055		)
Stock-based compensation	10,298			10,432
Deferred income tax expense	24,835			56,568
Change in TRA liability	—			82
Loss on derivatives	100,126			20,259
Net cash paid for derivative settlements	(15,111		)	(7,211		)
Net cash paid for option premiums	(23,609		)	(26,330		)
Other	1,623			2,001
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable	(13,417		)	(42,993		)
Accounts receivable—related parties	(798		)	147
Other current assets	7,245			(31,419		)
Other noncurrent assets	(805		)	(318		)
Accounts payable and accrued expenses	18,465			(32,213		)
Revenue and severance taxes payable	4,866			24,823
Net cash provided by operating activities	615,882			490,981
CASH FLOWS FROM INVESTING ACTIVITIES:
Development of oil and natural gas properties	(737,194		)	(854,228		)
Acquisitions of oil and natural gas properties	(24,591		)	(56,014		)
Additions to other property and equipment	(27,911		)	(48,047		)
Proceeds from sales of property, plant and equipment	37,893			42,553
Maturity of short-term investments	—			49,627
Other	4,489			35,018
Net cash used in investing activities	(747,314		)	(831,091		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under long-term debt	352,000			—
Payments on long-term debt	(312,000		)	(1,461		)
Payments on financing lease obligations	(1,430		)	—
Debt issuance costs	—			(45		)
Repurchase of common stock	(5,652		)	(10,871		)
Distributions to owners from consolidated subsidiary	(603		)	—
Net cash provided by (used in) financing activities	32,315			(12,377		)
Net decrease in cash, cash equivalents and restricted cash	(99,117		)	(352,487		)
Cash, cash equivalents and restricted cash at beginning of period	163,216			554,189
Cash, cash equivalents and restricted cash at end of period	$	64,099		$	201,702
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	(58,164	)	$	(64,047	)
Cash received for income taxes	$	240		$	—
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate	$	1,208		$	940
Additions to oil and natural gas properties - change in capital accruals	$	41,124		$	46,969
Net premiums on options that settled during the period	$	(19,748	)	$	(34,598	)

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

Table of Contents

PARSLEY ENERGY, INC. AND SUBSIDIARIES

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, a direct majority owned subsidiary of the Company (“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 intracompany 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 and six months ended June 30, 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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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 June 30, 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 Issued Accounting Pronouncements not yet Adopted

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU 2016-13 was subsequently amended by ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and ASU 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU 2016-13, as amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. ASU 2016-13 will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this ASU will have a material impact on the Company’s consolidated financial statements as the Company does not have a history of material credit losses.

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 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 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 standard for the comparative periods. The Company adopted the 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 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 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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 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 of the operating lease liability is included 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.

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 has 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. For the three months ended June 30, 2019, the applicable line items on the condensed consolidated statements of operations include $8.3 million of NGLs sales completed at the plant inlet. For the three months ended June 30, 2019, there were no natural gas sales completed at the plant inlet. For the six months ended June 30, 2019, the applicable line items on the condensed consolidated statements of operations include $2.9 million and $15.5 million of natural gas and NGLs sales, respectively, completed at the plant inlet. For the three and six months ended June 30, 2018, the applicable line items on the condensed consolidated statements of operations include $3.9 million and $16.3 million of natural gas and $8.6 million and $26.8 million of NGLs sales, respectively, completed at the plant inlet.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 and six months ended June 30, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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, Midland, Magellan East Houston (“MEH”) and Brent 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

As of June 30, 2019, the Company had the following outstanding oil derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.



Put spreads⁽¹⁾	Six Months Ending December 31, 2019						Year Ending December 31, 2020
	Cushing		Midland		MEH		Cushing		Midland		MEH
Volume (MBbls)	3,600		900		900		—		—		900
Long put price (per Bbl)	$	57.29	$	60.00	$	60.00	$	—	$	—	$	70.00
Short put price (per Bbl)	$	47.29	$	50.00	$	50.00	$	—	$	—	$	60.00



Three-way collars	Six Months Ending December 31, 2019								Year Ending December 31, 2020
	Cushing		Midland		MEH		Brent		Cushing		Midland		MEH		Brent
Volume (MBbls)	4,800		900		600		—		—		1,200		12,000		600
Short call price (per Bbl)	$	72.69	$	64.65	$	75.00	$	—	$	—	$	77.50	$	76.03	$	75.00
Long put price (per Bbl)	$	51.88	$	50.00	$	60.00	$	—	$	—	$	61.25	$	59.40	$	62.00
Short put price (per Bbl)	$	42.81	$	45.00	$	50.00	$	—	$	—	$	51.25	$	49.40	$	52.00



Two-way collars	Six Months Ending December 31, 2019
	Cushing
Volume (MBbls)	3,900
Short call price (per Bbl)	$	58.32
Long put price (per Bbl)	$	54.53



Basis swaps	Six Months Ending December 31, 2019				Year Ending December 31, 2020
	Volume (MBbls)	Basis Differential (per Bbl)			Volume (MBbls)	Basis Differential (per Bbl)
Basis swap - Midland - Cushing index⁽²⁾	6,600	$	(1.21	)	900	$	0.25
Basis swap - Houston - Cushing index⁽²⁾	390	$	5.10		—	$	—



(1)	Excludes 3,000 notional MBbls with a fair value of $13.9 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 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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	Six Months Ending December 31, 2019
	Henry Hub
Volume (MMbtu)	6,000,000
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⁾	6,000,000		$	(1.71	)



(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 gains (losses) on derivative instruments for the three and six months ended June 30, 2019 and 2018 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Changes in fair value of derivative instruments	$	28,016		(2,447		)	$	(83,332	)	(10,367		)
Net derivative settlements	(8,455		)	(7,019		)	(16,794		)	(9,892		)
Gain (loss) on derivatives	$	19,561		$	(9,466	)	$	(100,126	)	$	(20,259	)

Net premiums on options that settled during the period ⁽¹⁾	$	(10,232	)	$	(18,072	)	$	(19,748	)	$	(34,598	)



(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 Gain (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 17—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 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 and six months ended June 30, 2019 and 2018, the Company did not receive or post any material margins in connection with collateralizing its derivative positions.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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
June 30, 2019
Derivative assets with right of offset or master netting agreements	$	187,799		$	(13,946	)	$	173,853
Derivative liabilities with right of offset or master netting agreements	(204,858		)	13,946			(190,912		)

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 June 30, 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 and six months ended June 30, 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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 5. PROPERTY, PLANT AND EQUIPMENT

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



	June 30, 2019			December 31, 2018
Oil and natural gas properties:
Subject to depletion	$	7,594,669		$	6,659,444
Not subject to depletion
Incurred in 2019	310,549			—
Incurred in 2018	402,583			677,920
Incurred in 2017 and prior	2,367,828			2,610,882
Total not subject to depletion	3,080,960			3,288,802
Oil and natural gas properties, successful efforts method	10,675,629			9,948,246
Less accumulated depreciation, depletion and impairment	(1,647,036		)	(1,295,098		)
Total oil and natural gas properties, net	9,028,593			8,653,148
Other property, plant and equipment	231,006			206,662
Less accumulated depreciation	(42,862		)	(35,923		)
Other property, plant and equipment, net	188,144			170,739
Total property, plant and equipment, net	$	9,216,737		$	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 $194.0 million and $363.9 million for the three and six months ended June 30, 2019, respectively, and $141.9 million and $259.5 million for the three and six months ended June 30, 2018, respectively. The Company had no exploratory wells in progress at June 30, 2019 or December 31, 2018.

NOTE 6. ACQUISITIONS AND DIVESTITURES

Acquisitions

During the three and six months ended June 30, 2019, the Company incurred costs of $10.8 million and $24.6 million, respectively, related to the purchase of leasehold acreage. During the three and six months ended June 30, 2019, the Company reflected $4.8 million and $16.5 million, respectively, as part of costs not subject to depletion and $6.0 million and $8.1 million, respectively, as part of costs subject to depletion within its oil and natural gas properties.

During the three and six months ended June 30, 2018, the Company incurred costs of $28.6 million and $56.0 million, respectively, related to the acquisition of leasehold acreage. During the three and six months ended June 30, 2018, the Company reflected $27.0 million and $50.9 million, respectively, as part of costs not subject to depletion and $1.6 million and $5.1 million, respectively, as part of costs subject to depletion within its oil and natural gas properties.

During each of the three and six months ended June 30, 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 and six months ended June 30, 2019, the Company closed sales of certain leasehold acreage for proceeds of $20.4 million and $37.9 million, including customary purchase price adjustments. Upon closing these sales, the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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”).

During the three months ended June 30, 2018, the Company closed the sale of certain surface and mineral acreage for proceeds of $34.4 million, subject to customary purchase price adjustments, which was considered a receivable as of June 30, 2018 and is included in other current assets on the Company’s consolidated balance sheets and as other investing activities on the Company’s consolidated statements of cash flows. The Company recognized a $5.2 million gain on the sale.

During the six months ended June 30, 2018, the Company also closed sales of certain leasehold acreage for proceeds of $42.6 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 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 six months ended June 30, 2019 (in thousands):



	June 30, 2019
Asset retirement obligations, beginning of period	$	26,884
Additional liabilities incurred	519
Accretion expense	698
Liabilities settled upon plugging and abandoning wells	(482		)
Disposition of wells	(169		)
Revision of estimates	689
Asset retirement obligations, end of period	$	28,139

NOTE 8. DEBT

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



	June 30, 2019			December 31, 2018
Revolving Credit Agreement due 2021	$	40,000		$	—
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	2,240,000			2,204,202
Debt issuance costs on senior unsecured notes	(21,183		)	(22,918		)
Premium on senior unsecured notes	2,538			2,796
Less: current portion of debt	—			(2,413		)
Total long-term debt	$	2,221,355		$	2,181,667


(1)	As a result of the implementation of ASU No. 2016-02, Leases (Topic 842), as of June 30, 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Revolving Credit Agreement

On April 23, 2019, Parsley LLC, as borrower, the Company, 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 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 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.

As of June 30, 2019, the borrowing base under the Revolving Credit Agreement was $2.7 billion with a commitment level of $1.0 billion. Parsley LLC had $40.0 million in borrowings outstanding at an interest rate of 3.67% and $8.7 million in letters of credit outstanding at a weighted average interest rate of 1.25%, resulting in $951.3 million of availability under the Revolving Credit Agreement as of June 30, 2019. 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.

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”) limit 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 June 30, 2019, the Company was in compliance with all required covenants under the Revolving Credit Agreement and each of the indentures governing the Notes.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Interest Expense

The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2019 and 2018 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Cash payments for interest	$	27,671		$	34,592		$	58,164		$	64,047
Change in interest accrual	4,869			(1,890		)	6,322			(437		)
Amortization of deferred loan origination costs	1,186			1,185			2,371			2,374
Amortization of bond premium	(129		)	(129		)	(258		)	(258		)
Total interest expense, net	$	33,597		$	33,758		$	66,599		$	65,726

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 of the Company’s finance leases also include an option 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 the Company’s operating assets, are offset by amounts received from other working interest owners. Because the majority of the Company’s leases do not 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 June 30, 2019 were as follows (in thousands):



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
Finance lease costs:
Amortization of right-of-use assets	$	761		$	1,442
Interest on lease liabilities	69			129
Operating lease costs⁽¹⁾	24,578			48,006
Short-term lease costs⁽²⁾	5,674			11,721
Variable lease costs⁽³⁾	4,711			8,449
Sublease income	(129		)	(226		)
Total lease costs	$	35,664		$	69,521

(1)

For the three and six months ended June 30, 2019, operating lease costs are included in the following line items on the Company’s condensed consolidated financial statements: $18.2 million and $37.7 million, respectively, are capitalized as part of Oil and natural gas properties; $2.6 million and $5.2 million, respectively, are included in General and administrative expenses; $1.7 million and $3.0 million, respectively, are included in Lease operating expenses; and $2.0 million and $2.0 million, respectively, are included in Other operating expenses.

(2)

Short-term lease costs represent costs related to leases with a contract term of one year or less. For the three and six months ended June 30, 2019, short-term lease costs are included in the following line items on the Company’s condensed consolidated financial statements: $0.3 million and $3.1 million, respectively, are capitalized as part of Oil and natural gas properties and $5.4 million and $8.6 million, respectively, are 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 June 30, 2019, variable lease costs are included in the following line items on the Company’s condensed consolidated financial statements: $2.0 million and $4.4 million, respectively, are capitalized as part of Oil and natural gas properties and $2.8 million and $4.1 million, respectively, are included in General and administrative expenses.

Supplemental cash flow information related to the Company’s leases as of June 30, 2019 was as follows (in thousands):



Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	10,181
Investing cash flows from operating leases	$	38,137
Operating cash flows from finance leases	$	129
Financing cash flows from finance leases	$	1,430

Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	96,339
Finance leases	$	2,618

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Supplemental balance sheet information related to the Company’s leases as of June 30, 2019 was as follows (in thousands):



Operating leases
Assets
Operating lease assets, net of accumulated depreciation	$	179,066
Liabilities
Current operating lease liabilities	(79,719		)
Operating lease liability	(102,479		)
Total operating lease liabilities	$	(182,198	)

Finance leases
Assets
Property and equipment, gross	$	9,964
Accumulated depreciation	(5,065		)
Property and equipment, net	$	4,899
Liabilities
Other current liabilities	$	(2,656	)
Financing lease liability	(2,294		)
Total finance liabilities	$	(4,950	)

Weighted average remaining lease term (in years)
Operating leases	3.0
Finance leases	2.1

Weighted average discount rate
Operating leases	4.7		%
Finance leases	5.5		%

Maturities of Lease Liabilities

Maturities of the Company’s lease liabilities as of June 30, 2019 were as follows (in thousands):



	Operating leases			Finance leases
2019	$	44,724		$	1,528
2020	71,877			2,343
2021	41,654			1,187
2022	16,093			184
2023	8,616			13
Thereafter	12,698			—
Total lease payments	$	195,662		$	5,255
Less imputed interest	(13,464		)	(305		)
Total lease obligations	$	182,198		$	4,950
Less: Current obligations	$	(79,719	)	$	(2,656	)
Long-term lease obligations	$	102,479		$	2,294

In addition, during the six months ended June 30, 2019, the Company had entered into a contract for a 12-year real estate lease that will commence between fiscal years 2021 and 2022. On commencement of the lease, the Company will record an additional operating lease liability of approximately $171.0 million.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

As of December 31, 2018, minimum future contractual payments for long-term operating leases under the scope of ASC 840 were as follows (in thousands):



	Operating leases ⁽¹⁾		Finance leases
2019	$	71,998	$	2,413
2020	39,403		1,288
2021	26,658		436
2022	22,473		51
2023	21,822		14
Thereafter	148,508		—
Total lease payments	$	330,862	$	4,202


(1)	Operating leases included minimum future contractual payments for long-term operating leases that have not commenced.

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 and six months ended June 30, 2019 and 2018, Class B common stock was 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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Basic EPS (in thousands, except per share data)
Numerator:
Basic net income attributable to Parsley Energy, Inc. Stockholders	$	115,935	$	119,155	$	91,871	$	202,045
Denominator:
Basic weighted average shares outstanding	279,706		272,239		279,253		266,479
Basic EPS attributable to Parsley Energy, Inc. Stockholders	$	0.41	$	0.44	$	0.33	$	0.76
Diluted EPS
Numerator:
Net income attributable to Parsley Energy, Inc. Stockholders	115,935		119,155		91,871		202,045
Diluted net income attributable to Parsley Energy, Inc. Stockholders	$	115,935	$	119,155	$	91,871	$	202,045
Denominator:
Basic weighted average shares outstanding	279,706		272,239		279,253		266,479
Effect of dilutive securities:
Time-Based Restricted Stock and Time-Based Restricted Stock Units	62		607		110		564
Diluted weighted average shares outstanding ⁽¹⁾	279,768		272,846		279,363		267,043
Diluted EPS attributable to Parsley Energy, Inc. Stockholders	$	0.41	$	0.44	$	0.33	$	0.76


(1)	As of June 30, 2019 and 2018, there were 1,148,747 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 and six months ended June 30, 2019 or 2018 because the

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performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period.

Noncontrolling Interests

During the six months ended June 30, 2019, certain holders of PE Units (“PE Unit Holders”), including an officer of the Company, exercised their rights to exchange PE Units under the Parsley LLC Agreement, collectively electing to exchange 1,009,586 PE Units (and a corresponding number of shares of Class B common stock) for 1,009,586 shares of the Company’s Class A common stock, par value $0.01 per 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 each of the exchanging PE Unit Holders in satisfaction of their elections. As a result of these exchanges of PE Units (and corresponding shares of Class B common stock) for shares of Class A common stock during the six months ended June 30, 2019, the Company’s ownership in Parsley LLC increased from 88.5% to 88.8% and the ownership of the PE Unit Holders in Parsley LLC decreased from 11.5% to 11.2%. 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 income attributable to noncontrolling interests (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Net income attributable to the noncontrolling interests of:
Parsley LLC	$	19,046	$	21,704	$	15,105	$	44,119
Pacesetter Drilling, LLC	13		99		15		257
Total net income attributable to noncontrolling interests	$	19,059	$	21,803	$	15,120	$	44,376

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 and six months ended June 30, 2019 and 2018 is as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Time-based restricted stock	$	1,104	$	2,166	$	2,510	$	4,054
Time-based restricted stock units	2,188		1,377		4,499		3,032
Performance-based restricted stock⁽¹⁾	901		1,820		2,094		3,346
Performance-based restricted stock units	783		—		1,195		—
Total stock-based compensation	$	4,976	$	5,363	$	10,298	$	10,432


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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 $32.4 million of unamortized compensation expense relating to outstanding RSAs, RSUs, PSAs and PSUs at June 30, 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.

The following table summarizes the Company’s stock-based compensation award activity for the six months ended June 30, 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⁾	—			942,825			—			376,166
Vested	(309,699		)	(294,927		)	(481,820		)	(2,455		)
Forfeited	(19,763		)	(132,757		)	(66,112		)	(15,471		)
Outstanding at June 30, 2019	386,390			1,238,495			790,507			358,240

(1) Weighted average grant date fair value	$	—		$	17.92		$	—		$	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 six months ended June 30, 2019 and 2018 was 18.8% and 18.7%, respectively. During the three and six months ended June 30, 2019, the Company recognized income tax expense of $32.6 million and $24.8 million, respectively. During the three and six months ended June 30, 2018, the Company recognized income tax expense of $33.2 million and $56.6 million, respectively. The Company’s income tax expense for the three and six months ended June 30, 2019 differs 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 six months ended June 30, 2019 was a decrease in deferred tax liability of $0.2 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

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(Unaudited)

portion of the Company’s payments under the TRA constituting imputed interest. As of June 30, 2019, there have been no payments associated with the TRA.

As a result of the exchange of PE Units for shares of Class A common stock by a TRA Holder during the six months ended June 30, 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.

As of June 30, 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 PE Units for shares of Class A common stock, 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.

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 June 30, 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 14. RESTRUCTURING AND OTHER TERMINATION COSTS

During the three and six months ended June 30, 2019, the Company incurred restructuring and termination costs as part of the Company’s continuing effort to reduce future general and administrative expenses, which included a reduction in employee count. These one-time, nonrecurring costs are reflected in Restructuring and other termination costs in the Company’s condensed consolidated statements of operations included within this Quarterly Report. The following table summarizes the Company’s termination costs for the three and six months ended June 30, 2019 and 2018, respectively (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Termination costs	$	1,562	$	—	$	1,562	$	—
Total restructuring and other termination costs	$	1,562	$	—	$	1,562	$	—

The Company has not recorded an additional liability for restructuring costs as no additional costs have been incurred.

NOTE 15. RELATED PARTY TRANSACTIONS

Well Operations

During each of the three and six months ended June 30, 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 for the three and six months ended June 30, 2019 totaled $2.0 million and $2.5 million, respectively. The revenues disbursed to such Related Party Working Interest Owners for the three and six months ended June 30, 2018 totaled $0.4 million and $0.9 million, respectively.

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.

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 and six months ended June 30, 2019, the Company incurred charges totaling $2.3 million and $3.9 million, respectively, as compared to $4.0 million and $8.0 million, respectively, for the three and six months ended June 30, 2018, 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 and six months ended June 30, 2018, the Company incurred charges totaling $1.1 million and $3.7 million, respectively, for services performed by Lone Star for the Company’s well operations and drilling activities. The Company incurred no such charges during the three and six months ended June 30, 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 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 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 correspondingly increases. Refer to Note 10—Equity—Noncontrolling Interests for additional discussion.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

During the six months ended June 30, 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 16. SIGNIFICANT CUSTOMERS

For the six months ended June 30, 2019 and 2018, the following customers accounted for more than 10% of the Company’s revenue:



	Six Months Ended June 30,
	2019	2018
Shell Trading (US) Company	58%	54%
Lion Oil, Inc.	27%	21%
Targa Pipeline Mid-Continent, LLC	8%	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.

NOTE 17. 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 leasehold 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. The Company recognized leasehold abandonment and impairment charges of $22.2 million during the six months ended June 30, 2019 and $3.1 million and $8.3 million during the three and six months ended June 30, 2018, respectively. The Company incurred no such charges for the three months ended June 30, 2019.

Proved Oil and Natural Gas Properties. During each of the three and six months ended June 30, 2019 and 2018, the Company did not recognize impairment charges, as the carrying amount of the Company’s proved oil and natural gas properties exceeded their undiscounted future cash flows.

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.

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):



	June 30, 2019
	Level 1		Level 2			Level 3		Total
Assets:
Commodity derivative instruments⁽¹⁾	$	—	$	173,853		$	—	$	173,853
Total assets	$	—	$	173,853		$	—	$	173,853

Liabilities:
Commodity derivative instruments⁽¹⁾	$	—	$	(190,912	)	$	—	$	(190,912	)
Total liabilities	$	—	$	(190,912	)	$	—	$	(190,912	)
Net liability	$	—	$	(17,059	)	$	—	$	(17,059	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	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):



	June 30, 2019		December 31, 2018
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Long-term debt:
6.250% senior unsecured notes due 2024	400,000	419,756	400,000	394,144
5.375% senior unsecured notes due 2025	650,000	666,406	650,000	605,885
5.250% senior unsecured notes due 2025	450,000	458,199	450,000	424,980
5.625% senior unsecured notes due 2027	700,000	730,905	700,000	636,041
Revolving Credit Agreement	40,000	40,000	—	—

The fair values of the Notes were determined using the June 30, 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 June 30, 2019, there are no indicators for change in the Company’s market spread.

NOTE 18. SUBSEQUENT EVENTS

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

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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 281,116,921 PE Units as of June 30, 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 June 30, 2019, we held 252,850 gross (190,976 net) leasehold 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 June 30, 2019, we operated the following wells:



	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	864	709.9	421	392.4	1,285	1,102.3
Delaware Basin	13	12.5	104	98.9	117	111.4
Total	877	722.4	525	491.3	1,402	1,213.7

As of June 30, 2019, we held an interest in 1,870 gross (1,274.9 net) wells, including wells that we do not operate.

From the commencement of our horizontal drilling program in 2013 through June 30, 2019, we have placed on production 421 gross (392.4 net) horizontal wells in the Midland Basin and 104 gross (98.9 net) horizontal wells in the Delaware Basin. The table below summarizes the horizontal wells placed on production during the periods indicated:



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Area	Gross	Net	Gross	Net
Midland Basin	33	29.7	58	53.0
Delaware Basin	6	6.0	15	14.3
Total	39	35.7	73	67.3

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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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Oil sales	92	%	85	%	89	%	86	%
Natural gas sales	0	%	3	%	2	%	3	%
Natural gas liquids sales	8	%	12	%	9	%	11	%

Other revenues are not material and include fees charged by certain of our subsidiaries. During each of the three and six months ended June 30, 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 and six months ended June 30, 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 and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Oil (MBbls)	7,881	6,165	14,983	11,506
Natural gas (MMcf)	13,004	9,235	23,492	17,791
Natural gas liquids (MBbls)	2,701	2,106	5,137	3,749
Total (MBoe)	12,749	9,811	24,035	18,221
Average net production (Boe/d)	140,099	107,813	132,790	100,669

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 differ from our historical hedging strategy. 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 June 30, 2019.

We will have recognized the following cumulative losses in Gain (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):



Q3 2019	$	(14,486	)
Q4 2019	(14,486		)
Q1 2020	(9,864		)
Q2 2020	(9,864		)
Q3 2020	(2,865		)
Q4 2020	(2,865		)
Total	$	(54,430	)

Recent Matters

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 and six months ended June 30, 2019 and 2018, we did not recognize an impairment of our proved oil and natural gas properties. At June 30, 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 73% per field and, individually, by a minimum of 59%.

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 June 30, 2018 to June 30, 2019. We evaluate future commodity pricing for oil and NGLs based on five-year WTI futures prices, which decreased from June 30, 2018 to June 30, 2019, and future commodity pricing for natural gas based on five-year Henry Hub futures prices, which decreased from June 30, 2018 to June 30, 2019. The increase in value of undiscounted cash flows from June 30, 2018 to June 30, 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 June 30, 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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Capital expenditures	$	372,014	$	477,111	$	778,318	$	901,197

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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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Production revenues (in thousands):
Oil sales	$	458,888	$	396,325	$	827,014	$	727,428
Natural gas sales	141		12,235		14,593		29,659
Natural gas liquids sales	38,312		57,275		82,097		97,895
Total revenues	$	497,341	$	465,835	$	923,704	$	854,982

Average realized prices ⁽¹⁾:
Oil, without realized derivatives (per Bbls)	$	58.23	$	64.29	$	55.20	$	63.22
Oil, with realized derivatives (per Bbls)	55.42		60.11		52.56		59.28
Natural gas, without realized derivatives (per Mcf)	0.01		1.32		0.62		1.67
Natural gas, with realized derivatives (per Mcf)	0.28		1.40		0.75		1.72
Natural gas liquids (per Bbls)	14.18		27.20		15.98		26.11
Average price per Boe, without realized derivatives	39.01		47.48		38.43		46.92
Average price per Boe, with realized derivatives	37.54		44.92		36.91		44.48

Production:
Oil (MBbls)	7,881		6,165		14,983		11,506
Natural gas (MMcf)	13,004		9,235		23,492		17,791
Natural gas liquids (MBbls)	2,701		2,106		5,137		3,749
Total (MBoe)	12,749		9,811		24,035		18,221

Average daily production volume:
Oil (Bbls)	86,604		67,747		82,779		63,569
Natural gas (Mcf)	142,901		101,484		129,790		98,293
Natural gas liquids (Bbls)	29,681		23,143		28,381		20,713
Total (Boe)	140,099		107,813		132,790		100,669



(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.

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. During the three and six months ended June 30, 2019, most of our oil production was sold at NYMEX WTI and most of our natural gas production was sold at Waha Hub prices.

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	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Average realized oil price ($/Bbl)	$	58.23		$	64.29		$	55.20		$	63.22
Average NYMEX ($/Bbl)	$	59.96		$	67.86		$	57.37		$	65.48
Differential to NYMEX	$	(1.73	)	$	(3.57	)	$	(2.17	)	$	(2.26	)
Average realized oil price as a percentage of average NYMEX oil price	97		%	95		%	96		%	97		%
Average realized natural gas price ($/Mcf)	$	0.01		$	1.32		$	0.62		$	1.67
Average NYMEX ($/Mcf)	$	2.51		$	2.83		$	2.69		$	2.84
Differential to NYMEX	$	(2.50	)	$	(1.51	)	$	(2.07	)	$	(1.17	)
Average realized natural gas price as a percentage of average NYMEX gas price	0		%	47		%	23		%	59		%
Average realized NGLs price ($/Bbl)	$	14.18		$	27.20		$	15.98		$	26.11
Average NYMEX ($/Bbl)	$	59.96		$	67.86		$	57.37		$	65.48
Differential to NYMEX	$	(45.78	)	$	(40.66	)	$	(41.39	)	$	(39.37	)
Average realized NGLs price as a percentage of average NYMEX oil price	24		%	40		%	28		%	40		%

As reflected in the table above, our price differential for oil widened significantly during the second quarter of 2018, and this price differential continued to widen throughout much of the year. During the three and six months ended June 30, 2019, our price differential for oil narrowed, although it could widen during all or a portion of the remainder of 2019.

Our average realized price for natural gas is based on Waha Hub prices. During 2018 and the first quarter of 2019, Waha Hub natural gas prices averaged approximately $1.50 per MMBtu. However, natural gas prices decreased significantly in the second quarter of 2019, during which the average daily Waha Hub natural gas prices were approximately $(0.07) per MMBtu. These negative natural gas prices resulted in significantly higher price differentials for our natural gas production during the second quarter of 2019. As a result of the higher price differential, our realized average natural gas price for the three months ended June 30, 2019 was $0.01 per MMBtu.

Widening oil and natural gas basis differentials are largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGLs production. As of June 30, 2019, we had not experienced material pipeline-related interruptions to our oil, natural gas or NGLs production.

Oil, natural gas and NGLs revenues. Our oil, natural gas and NGLs revenues increased by $31.5 million, or 7%, to $497.3 million for the three months ended June 30, 2019 from $465.8 million for the three months ended June 30, 2018.

As shown in the following tables, from the three months ended June 30, 2018 to the three months ended June 30, 2019, the net dollar effect of the decrease in oil, natural gas and NGLs prices was $100.0 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs was $131.5 million.



	Change in prices			Three months ended June 30, 2019 Production volumes	Total net dollar effect of change
Effect of change in price:				(in thousands)	(in thousands)
Oil (per Bbls)	$	(6.06	)	7,881	$	(47,752	)
Natural gas (per Mcf)	(1.31		)	13,004	(17,087		)
Natural gas liquids (per Bbls)	(13.02		)	2,701	(35,145		)
Total revenues due to change in price					$	(99,984	)

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	Change in production volumes	Three months ended June 30, 2018 Average prices		Total net dollar effect of change
Effect of change in production volumes:	(in thousands)			(in thousands)
Oil (MBbls)	1,716	$	64.29	$	110,315
Natural gas (MMcf)	3,769	1.32		4,993
Natural gas liquids (MBbls)	595	27.20		16,182
Total revenues due to change in production volumes				$	131,490

Oil, natural gas and NGLs revenues. Our oil, natural gas and NGLs revenues increased by $68.7 million, or 8%, to $923.7 million for the six months ended June 30, 2019 from $855.0 million for the six months ended June 30, 2018.

As shown in the following tables, from the six months ended June 30, 2018 to the six months ended June 30, 2019, the net dollar effect of the decrease in oil, natural gas and NGLs prices was $196.8 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs was $265.6 million.



	Change in prices			Six months ended June 30, 2019 Production volumes	Total net dollar effect of change
Effect of change in price:				(in thousands)	(in thousands)
Oil (per Bbls)	$	(8.02	)	14,983	$	(120,236	)
Natural gas (per Mcf)	(1.05		)	23,492	(24,569		)
Natural gas liquids (per Bbls)	(10.13		)	5,137	(52,042		)
Total revenues due to change in price					$	(196,847	)



	Change in production volumes	Six months ended June 30, 2018 Average prices		Total net dollar effect of change
Effect of change in production volumes:	(in thousands)			(in thousands)
Oil (MBbls)	3,477	$	63.22	$	219,822
Natural gas (MMcf)	5,701	1.67		9,503
Natural gas liquids (MBbls)	1,388	26.11		36,244
Total revenues due to change in production volumes				$	265,569

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Operating expenses

The following table summarizes our expenses for the periods indicated:



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019		2018
Operating expenses (in thousands):
Lease operating expenses	$	42,696	$	35,904		$	83,868	$	64,736
Transportation and processing costs	6,608		6,471			14,865		12,738
Production and ad valorem taxes	30,744		27,331			58,151		51,517
Depreciation, depletion and amortization	198,563		145,552			372,286		266,751
General and administrative expenses ⁽¹⁾	34,907		35,991			72,944		70,986
Exploration and abandonment costs	72		3,366			23,066		8,777
Acquisition costs	—		(2		)	—		2
Accretion of asset retirement obligations	353		359			698		713
Gain on sale of property	—		(5,166		)	—		(5,055		)
Restructuring and other termination costs	1,562		—			1,562		—
Other operating expenses	2,199		2,477			1,388		4,652
Total operating expenses	$	317,704	$	252,283		$	628,828	$	475,817

Expense per Boe:
Lease operating expenses	$	3.35	$	3.66		$	3.49	$	3.55
Transportation and processing costs	0.52		0.66			0.62		0.70
Production and ad valorem taxes	2.41		2.79			2.42		2.83
Depreciation, depletion and amortization	15.57		14.84			15.49		14.64
General and administrative expenses	2.74		3.67			3.03		3.90
Exploration and abandonment costs	0.01		0.34			0.96		0.48
Acquisition costs	—		—			—		—
Accretion of asset retirement obligations	0.03		0.04			0.03		0.04
Gain on sale of property	—		(0.53		)	—		(0.28		)
Restructuring and other termination costs	0.12		—			0.06		—
Other operating expenses	0.17		0.25			0.06		0.26
Total operating expenses per Boe	$	24.92	$	25.72		$	26.16	$	26.12


(1)	General and administrative expenses include stock-based compensation expense of $5.0 million and $10.3 million for the three and six months ended June 30, 2019, respectively, and $5.4 million and $10.4 million for the three and six months ended June 30, 2018, respectively.

Lease operating expenses. Lease operating expenses were $42.7 million and $83.9 million for the three and six months ended June 30, 2019, respectively, as compared to $35.9 million and $64.7 million for the three and six months ended June 30, 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 decreased $0.31 per Boe, or 8%, to $3.35 for the three months ended June 30, 2019 from $3.66 for the three months ended June 30, 2018 and $0.06 per Boe, or 2%, to $3.49 for the six months ended June 30, 2019 from $3.55 for the six months ended June 30, 2018. The decreases in lease operating expenses per Boe are primarily attributable to the increases in production over the applicable periods.

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 $6.6 million and $14.9 million for the three and six months ended June 30, 2019, respectively, as compared to $6.5 million and $12.7 million for the three and six months

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ended June 30, 2018, respectively. The increase is primarily due to the increase in production period over period as well as plant electricity charges. On a per Boe basis, transportation and processing costs were $0.52 and $0.62 per Boe for the three and six months ended June 30, 2019, respectively, and $0.66 and $0.70 per Boe for the three and six months ended June 30, 2018, respectively. The decreases in transportation and processing costs per Boe are primarily attributable to the increase in production period over period.

Production and ad valorem taxes. Production and ad valorem taxes were $30.7 million and $58.2 million for the three and six months ended June 30, 2019, respectively, as compared to $27.3 million and $51.5 million for the three and six months ended June 30, 2018, respectively. On a per Boe basis, production and ad valorem taxes decreased to $2.41 per Boe for the three months ended June 30, 2019 from $2.79 per Boe for the three months ended June 30, 2018 and to $2.42 per Boe for the six months ended June 30, 2019 from $2.83 per Boe for the six months ended June 30, 2018.

Overall, for the three and six months ended June 30, 2019, compared to the same periods in 2018, production taxes increased by approximately $0.5 million and $2.4 million, respectively, reflecting increased production volumes. Ad valorem taxes increased $2.9 million and $4.3 million over the same periods, reflecting higher property valuation assessments by local taxing authorities.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $198.6 million and $372.3 million for the three and six months ended June 30, 2019, respectively, as compared to $145.6 million and $266.8 million for the three and six months ended June 30, 2018, respectively.

These increases in DD&A are largely attributable to development activity that resulted in an increase in costs subject to depletion as of June 30, 2019 as compared to June 30, 2018 and 30% and 32% increases in production during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. These increases were partially offset by a 12% increase in total proved reserves and a 31% increase in proved developed reserves as of June 30, 2019, as compared to June 30, 2018.

On a per Boe basis, DD&A expense increased to $15.57 per Boe for the three months ended June 30, 2019 from $14.84 per Boe during the three months ended June 30, 2018, and DD&A expense increased to $15.49 per Boe for the six months ended June 30, 2019 from $14.64 per Boe for the six months ended June 30, 2018, in each case, primarily due to the increase in production volumes and reserves discussed above.

General and administrative expenses. General and administrative expenses were $34.9 million and $72.9 million during the three and six months ended June 30, 2019, respectively, and $36.0 million and $71.0 million during the three and six months ended June 30, 2018, respectively. The decrease for the three months ended June 30, 2019, as compared to the three months ended June 30, 2018, is primarily due to ongoing corporate cost savings initiatives, including a reduction in employee count. The increase for the six months ended June 30, 2019, as compared to the six months ended June 30, 2018, is primarily due to an increase in office rent expense offset by the corporate cost savings initiatives discussed above.

On a per Boe basis, general and administrative expenses were $2.74 and $3.03 per Boe during the three and six months ended June 30, 2019, respectively, as compared to $3.67 and $3.90 per Boe for the three and six months ended June 30, 2018, respectively. The decreases are a result of production volume growth outpacing general and administrative expenses.

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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Leasehold abandonments and impairments	$	—	$	3,144	$	22,189	$	8,323
Geological and geophysical costs	72		118		869		310
Other	—		104		8		144
Total exploration and abandonment costs	$	72	$	3,366	$	23,066	$	8,777

During the six months ended June 30, 2019, we recognized leasehold abandonment and impairment charges of approximately $22.2 million. During the three and six months ended June 30, 2018, we recognized leasehold abandonment and impairment charges of approximately $3.1 million and $8.3 million, respectively. There were no such charges for the three months ended June 30, 2019. Our leasehold abandonment and impairment charges primarily relate to the release or abandonment of our non-core acreage during these periods.

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During the three and six months ended June 30, 2019, we incurred geological and geophysical expenses of $0.1 million and $0.9 million, respectively, as compared to expenses of $0.1 million and $0.3 million for the same periods in 2018. 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 during the six months ended June 30, 2019 and $0.1 million and $0.1 million during the three and six months ended June 30, 2018, respectively. There were no such costs recognized during the three months ended June 30, 2019. Other exploration costs include research and other similar costs.

Acquisition costs. During the three and six months ended June 30, 2018, we incurred minimal acquisition costs which include non-recurring legal and other due diligence fees associated with certain acquisitions. During the three and six months ended June 30, 2019, we incurred no such acquisition costs.

Gain on sale of property. We recognized a gain on the sale of property of $5.2 million and $5.1 million during the three and six months ended June 30, 2018, respectively, as discussed in Note 6—Acquisitions and Divestitures to our condensed consolidated financial statements included elsewhere in this Quarterly Report. We recognized no such gains during the three and six months ended June 30, 2019.

Restructuring and other termination costs. During the three and six months ended June 30, 2019, we incurred one-time restructuring and other termination costs of $1.6 million as part of the Company’s continuing effort to reduce future general and administrative expenses, which included a reduction in employee headcount. We incurred no such restructuring and other termination costs for the three and six months ended June 30, 2018.

Other operating expenses. During the three and six months ended June 30, 2019, other operating expenses included idle charges of $2.2 million and $1.4 million, respectively. During the three and six months ended June 30, 2018, other operating expenses of $2.5 million and $4.7 million were 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 and six months ended June 30, 2019 as Pacesetter completed the sale of all of its physical assets during 2018.

Other income (expense)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Other income (expense) (in thousands):
Interest expense, net	$	(33,597	)	$	(33,758	)	$	(66,599	)	$	(65,726	)
Gain (loss) on derivatives	19,561			(9,466		)	(100,126		)	(20,259		)
Change in TRA liability	—			—			—			(82		)
Interest income	103			1,686			394			3,809
Other income	715			234			773			535
Total other expense, net	$	(13,218	)	$	(41,304	)	$	(165,558	)	$	(81,723	)

Interest expense, net. Interest expense, net for the three and six months ended June 30, 2019 was $33.6 million and $66.6 million, respectively, as compared to $33.8 million and $65.7 million, respectively, for the three and six months ended June 30, 2018.

Gain (loss) on derivatives. We recognized gain on derivatives of $19.6 million and loss on derivatives of $100.1 million during the three and six months ended June 30, 2019, respectively, as compared to losses on derivatives of $9.5 million and $20.3 million during the three and six months ended June 30, 2018, respectively. The change in gain (loss) on derivatives for each of the periods is attributable to entering into new hedge positions as well as the change in commodity prices. Where applicable, a decrease in the value of our commodity portfolio is generally attributable to higher commodity prices and, conversely, an increase in the value of our commodity portfolio is generally attributable to lower commodity prices.

Change in TRA liability. During the six months ended June 30, 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 June 30, 2018 or the three and six months ended June 30, 2019.

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Interest income. Interest income was $0.1 million and $0.4 million during the three and six months ended June 30, 2019, respectively, as compared to $1.7 million and $3.8 million, respectively, during the three and six months ended June 30, 2018. The change is a result of decreased interest income, including amortization, associated with our previous held-to-maturity securities.

Other income. Other income was $0.7 million and $0.8 million for the three and six months ended June 30, 2019, respectively, as compared to other income of $0.2 million and $0.5 million for the three and six months ended June 30, 2018, respectively. The increases in other income for the three and six months ended June 30, 2019, as compared to the same respective periods in 2018, are attributable to increases in income from our equity investment in Spraberry Production Services, LLC, offset by decreases in other miscellaneous items.

Income Tax Expense

During the three and six months ended June 30, 2019, we recognized income tax expense of $32.6 million and $24.8 million, respectively, as compared to income tax expense of $33.2 million and $56.6 million during the three and six months ended June 30, 2018, 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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Capital expenditures	$	372,014	$	477,111	$	778,318	$	901,197

Our 2019 budget for capital development expenditures is approximately $1,400.0 million to $1,500.0 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 capital expenditures during the remainder of 2019 is largely discretionary and within our control. We could choose to defer a portion of these planned 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 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 June 30, 2019, our liquidity was as follows (in millions):



Cash and cash equivalents	$	64.1
Revolving Credit Agreement availability	951.3
Liquidity	$	1,015.4

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

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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):



	Six Months Ended June 30,
	2019			2018
Net cash provided by operating activities	$	615,882		$	490,981
Net cash used in investing activities	(747,314		)	(831,091		)
Net cash provided by (used in) financing activities	32,315			(12,377		)

Cash flows provided by operating activities. Net cash provided by operating activities was approximately $615.9 million and $491.0 million for the six months ended June 30, 2019 and 2018, respectively. Net cash provided by operating activities increased primarily due to a $97.5 million increase associated with changes in working capital as well as a $65.7 million increase in total revenues due to increased production volumes, offset by a $26.7 million increase in cash based operating expenses, in each case, during the six months ended June 30, 2019 as compared to the six months ended June 30, 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 $747.3 million and $831.1 million for the six months ended June 30, 2019 and 2018, respectively. The reduction in the amount of cash used in investing activities was due primarily to a $117.0 million decrease in development costs related to our oil and natural gas properties and a $31.4 million decrease in acquisition costs, offset by a $49.6 million decrease in short-term investment maturities. 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 provided by (used in) financing activities. Net cash provided by financing activities was $32.3 million and net cash used in financing activities was $12.4 million for the six months ended June 30, 2019 and 2018, respectively. Net cash provided by financing activities increased primarily due to $40.0 million of outstanding borrowings under the Revolving Credit Agreement as of June 30, 2019.

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

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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 ($393.6) million and ($108.2) million at June 30, 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 $64.1 million and $163.2 million at June 30, 2019 and December 31, 2018, respectively. The $99.1 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 six months ended June 30, 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 six months ended June 30, 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 June 30, 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, 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 and natural gas 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 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 June 30, 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 June 30, 2019, the fair market value of our oil and natural gas derivative contracts was a net liability of $17.1 million, including deferred premium payables of $59.2 million. The deferred premium payable is a fixed amount and is not marked to fair market value. As of June 30, 2019, the fair market value of our oil derivative contracts was a net liability of $16.3 million. Based on our open oil derivative positions at June 30, 2019, a 10% increase in the NYMEX WTI price would increase our net oil derivative liability by approximately $74.5 million, while a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $73.0 million. As of June 30, 2019, the fair market value of our natural gas derivative contracts was a net liability of $0.8 million. Based on our open natural gas derivative positions at June 30, 2019, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative liability by approximately $0.3 million. Based on our open natural gas derivative positions at June 30, 2019, a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas derivative liability by approximately $0.4 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 June 30, 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 June 30, 2019, we had $40.0 million of outstanding borrowings under our Revolving Credit Agreement with an interest rate of 3.67%. Based on this amount outstanding, an increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $0.4 million.

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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 June 30, 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 June 30, 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 June 30, 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 June 30, 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
4/1/2019 - 4/30/2019	1,210	$	21.77	—	$	—
5/1/2019 - 5/31/2019	13,638	$	18.96	—	$	—
6/1/2019 - 6/30/2019	3,300	$	17.65	—	$	—
Total	18,148	$	18.91	—	$	—



(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		Seventh Amendment to Credit Agreement, dated 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).
10.2		Fourth Amended and Restated Limited Liability Company Agreement of Parsley Energy, LLC, dated July 22, 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 July 25, 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.

August 8, 2019	By:	/s/ Matt Gallagher
		Matt Gallagher
		President and Chief Executive Officer (Principal Executive Officer)


August 8, 2019	By:	/s/ Ryan Dalton
		Ryan Dalton
		Executive Vice President—Chief Financial Officer (Principal Accounting and Financial Officer)

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Matt Gallagher, certify that:



1.	I have reviewed this Quarterly Report on Form 10-Q (this “report”) of Parsley Energy, Inc. (the “registrant”);



2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and



5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.




August 8, 2019	By:	/s/ Matt Gallagher
		Matt Gallagher
		President and Chief Executive Officer

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Ryan Dalton, certify that:



1.	I have reviewed this Quarterly Report on Form 10-Q (this “report”) of Parsley Energy, Inc. (the “registrant”);



2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.




August 8, 2019	By:	/s/ Ryan Dalton
		Ryan Dalton
		Executive Vice President—Chief Financial Officer

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

UNDER SECTION 906 OF THE

SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019 of Parsley Energy, Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Matt Gallagher, President and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.




August 8, 2019	By:	/s/ Matt Gallagher
		Matt Gallagher
		President and Chief Executive Officer

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF THE

SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019 of Parsley Energy, Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ryan Dalton, Executive Vice President—Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.




August 8, 2019	By:	/s/ Ryan Dalton
		Ryan Dalton
		Executive Vice President—Chief Financial Officer