Pioneer PE Holding LLC - FORM 10-Q

Pioneer PE Holding LLC - FORM 10-Q - November 8, 2017

Attached files

Attached files

Pioneer PE Holding LLC Reports

file	filename
EX-32.2 - EXHIBIT 32.2 - Pioneer PE Holding LLC	ex-32210xq20170930.htm
EX-32.1 - EXHIBIT 32.1 - Pioneer PE Holding LLC	ex-32110xq20170930.htm
EX-31.2 - EXHIBIT 31.2 - Pioneer PE Holding LLC	ex-31210xq20170930.htm
EX-31.1 - EXHIBIT 31.1 - Pioneer PE Holding LLC	ex-31110xq20170930.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2017



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

For the transition period from to

Commission File Number: 001-36463

PARSLEY ENERGY, INC.

(Exact name of registrant as specified in its charter)



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

(737) 704-2300

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

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

As of November 8, 2017, the registrant had 249,949,864 shares of Class A common stock and 64,438,397 shares of Class B common stock outstanding.

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PARSLEY ENERGY, INC.

TABLE OF CONTENTS



		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Operations	8
	Condensed Consolidated Statement 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	31
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	51
Item 6.	Exhibits	51
	Signatures	52

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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 strategy, future operations, financial position, estimated revenues and losses, projected costs, 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, 2016 (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 or business acquisitions;


•	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)	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.



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



(9)	Exploitation. A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.



(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 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. Collectively, these are referred to as geological and geophysical costs or G&G costs.



	(ii)	Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title deference, 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.



	(vi)	Idle drilling rig fees which are not chargeable to joint operations.



(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. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).



(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.

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



(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)	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.



(18)	LIBOR. London Interbank Offered Rate.



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



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



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



(22)	MMBtu. One million British thermal units.



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



(24)	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.



(25)	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.



(26)	NYMEX. The New York Mercantile Exchange.



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



(28)	PE Units. The single class of units that represents all of the membership interests (including outstanding incentive units) in Parsley Energy, LLC.



(29)	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.



(30)	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, the project 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).



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



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

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



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



(32)	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).



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



(34)	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.



(35)	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.



(36)	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.



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



(38)	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.



(39)	Undeveloped acreage. Lease 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.



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



(41)	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.



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



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

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PART 1: FINANCIAL INFORMATION

Item 1: Financial Statements

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2017			December 31, 2016
	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	242,547		$	133,379
Restricted cash	4,448			3,290
Accounts receivable:
Joint interest owners and other	31,875			12,698
Oil, natural gas and NGLs	94,790			59,174
Related parties	207			290
Short-term derivative instruments, net	94,709			39,708
Other current assets	5,791			50,949
Total current assets	474,367			299,488
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method	8,150,403			4,063,417
Accumulated depreciation, depletion and impairment	(732,690		)	(506,175		)
Total oil and natural gas properties, net	7,417,713			3,557,242
Other property, plant and equipment, net	87,562			59,318
Total property, plant and equipment, net	7,505,275			3,616,560
NONCURRENT ASSETS
Long-term derivative instruments, net	60,953			16,416
Other noncurrent assets	8,838			6,318
Total noncurrent assets	69,791			22,734
TOTAL ASSETS	$	8,049,433		$	3,938,782

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses	$	313,905		$	162,317
Revenue and severance taxes payable	95,939			69,452
Current portion of long-term debt	8,037			67,214
Short-term derivative instruments, net	90,244			44,153
Current portion of asset retirement obligations	5,624			1,818
Total current liabilities	513,749			344,954
NONCURRENT LIABILITIES
Long-term debt	1,487,271			1,041,324
Asset retirement obligations	14,323			9,574
Deferred tax liability	9,234			5,483
Payable pursuant to TRA liability	114,876			94,326
Long-term derivative instruments, net	50,037			12,815
Total noncurrent liabilities	1,675,741			1,163,522
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, 247,890,053 shares issued and 247,739,464 shares outstanding at September 30, 2017 and 179,730,033 shares issued and 179,590,617 shares outstanding at December 31, 2016	2,479			1,797
Class B, $0.01 par value, 125,000,000 shares authorized, 66,655,716 and 28,008,573 shares issued and outstanding at September 30, 2017 and December 31, 2016	667			280
Additional paid in capital	4,608,515			2,151,197
Accumulated deficit	(6,400		)	(63,255		)
Treasury stock, at cost, 150,589 shares and 139,416 shares at September 30, 2017 and December 31, 2016	(681		)	(381		)
Total stockholders' equity	4,604,580			2,089,638
Noncontrolling interest	1,255,363			340,668
Total equity	5,859,943			2,430,306
TOTAL LIABILITIES AND EQUITY	$	8,049,433		$	3,938,782

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands, except per share data)
REVENUES
Oil sales	$	198,865		$	112,705		$	546,676		$	255,865
Natural gas sales	15,601			8,457			41,051			19,834
Natural gas liquids sales	26,547			10,770			64,296			24,811
Other	8			605			3,533			1,388
Total revenues	241,021			132,537			655,556			301,898
OPERATING EXPENSES
Lease operating expenses	29,525			16,407			76,783			44,509
Production and ad valorem taxes	14,808			8,391			37,367			18,993
Depreciation, depletion and amortization	94,819			65,741			247,104			171,113
General and administrative expenses (including stock-based compensation of $5,170 and $3,316 for the three months ended September 30, 2017 and 2016 and $14,630 and $9,466 for the nine months ended September 30, 2017 and 2016)	33,573			24,695			89,376			61,301
Exploration costs	88			3,113			5,293			12,779
Acquisition costs	2,449			440			10,969			926
Accretion of asset retirement obligations	268			190			597			575
Other operating expenses	2,419			1,220			7,205			3,767
Total operating expenses	177,949			120,197			474,694			313,963
OPERATING INCOME (LOSS)	63,072			12,340			180,862			(12,065		)
OTHER INCOME (EXPENSE)
Interest expense, net	(21,866		)	(15,561		)	(59,417		)	(38,954		)
Loss on sale of property	—			—			—			(119		)
Loss on early extinguishment of debt	—			—			(3,891		)	—
(Loss) gain on derivatives	(61,955		)	1,374			6,175			(23,842		)
Change in TRA liability	—			—			(20,549		)	—
Other income (expense)	508			(1,073		)	1,281			(1,605		)
Total other expense, net	(83,313		)	(15,260		)	(76,401		)	(64,520		)
(LOSS) INCOME BEFORE INCOME TAXES	(20,241		)	(2,920		)	104,461			(76,585		)
INCOME TAX BENEFIT (EXPENSE)	5,080			1,279			(25,538		)	21,765
NET (LOSS) INCOME	(15,161		)	(1,641		)	78,923			(54,820		)
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS	1,828			(1,065		)	(22,068		)	11,383
NET (LOSS) INCOME ATTRIBUTABLE TO PARSLEY ENERGY, INC. STOCKHOLDERS	$	(13,333	)	$	(2,706	)	$	56,855		$	(43,437	)

Net (loss) income per common share:
Basic	$	(0.05	)	$	(0.02	)	$	0.24		$	(0.28	)
Diluted	$	(0.05	)	$	(0.02	)	$	0.24		$	(0.28	)
Weighted average common shares outstanding:
Basic	246,518			173,241			237,725			156,018
Diluted	246,518			173,241			238,785			156,018

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)



	Issued Shares														Shares
	Class A Common Stock	Class B Common Stock		Class A Common Stock		Class B Common Stock			Additional paid in capital			Retained earnings (accumulated deficit)			Treasury stock	Treasury stock			Total stockholders’ equity			Noncontrolling interest			Total equity
	(In thousands)
Balance at December 31, 2016	179,730	28,008		$	1,797	$	280		$	2,151,197		$	(63,255	)	139	$	(381	)	$	2,089,638		$	340,668		$	2,430,306
Issuance proceeds, net of underwriters discount and expenses	66,700	—		667		—			2,122,860			—			—	—			2,123,527			—			2,123,527
Shares of Class B Common Stock issued for acquisition	—	39,849		—		399			1,182,919			—			—	—			1,183,318			—			1,183,318
Change in equity due to issuance of PE Units by Parsley LLC	—	—		—		—			(915,749		)	—			—	—			(915,749		)	915,749			—
Decrease in net deferred tax liability due to issuance of PE Units by Parsley LLC	—	—		—		—			29,169			—			—	—			29,169			—			29,169
Exchange of PE Units and Class B Common Stock for Class A Common Stock	1,201	(1,201	)	12		(12		)	23,492			—			—	—			23,492			(23,492		)	—
Investment in Pacesetter	—	—		—		—			—			—			—	—			—			370			370
Issuance of restricted stock	228	—		—		—			—			—			—	—			—			—			—
Vesting of restricted stock units	31	—		3		—			(3		)	—			—	—			—			—			—
Repurchase of common stock	—	—		—		—			—			—			11	(300		)	(300		)	—			(300		)
Restricted stock forfeited	—	—		—		—			(15		)	—			1	—			(15		)	—			(15		)
Stock-based compensation	—	—		—		—			14,645			—			—	—			14,645			—			14,645
Net income	—	—		—		—			—			56,855			—	—			56,855			22,068			78,923
Balance at September 30, 2017	247,890	66,656		$	2,479	$	667		$	4,608,515		$	(6,400	)	151	$	(681	)	$	4,604,580		$	1,255,363		$	5,859,943

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2017			2016
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	78,923		$	(54,820	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	247,104			171,113
Accretion of asset retirement obligations	597			575
Loss on sale of property	—			119
Loss on early extinguishment of debt	3,891			—
Amortization and write off of deferred loan origination costs	2,826			2,293
Amortization of bond premium	(387		)	(617		)
Stock-based compensation	14,630			9,466
Deferred income tax expense (benefit)	25,538			(21,765		)
Change in TRA liability	20,549			—
(Gain) loss on derivatives	(6,175		)	23,842
Net cash received for derivative settlements	13,845			28,678
Net cash paid for option premiums	(19,905		)	(2,270		)
Net premiums (paid) received on options that settled during the period	(22,404		)	26,181
Other	366			6,026
Changes in operating assets and liabilities, net of acquisitions:
Restricted cash	(1,158		)	(1,616		)
Accounts receivable	(54,793		)	(23,295		)
Accounts receivable—related parties	83			59
Other current assets	67,543			(38,436		)
Other noncurrent assets	(739		)	682
Accounts payable and accrued expenses	94,442			28,168
Revenue and severance taxes payable	26,487			20,817
Other noncurrent liabilities	—			2
Net cash provided by operating activities	491,263			175,202
CASH FLOWS FROM INVESTING ACTIVITIES:
Development of oil and natural gas properties	(733,179		)	(385,076		)
Acquisitions of oil and natural gas properties	(2,131,361		)	(864,870		)
Additions to other property and equipment	(31,947		)	(20,818		)
Proceeds from sales and exchanges of oil and natural gas properties	13,366			—
Other	2,893			—
Net cash used in investing activities	(2,880,228		)	(1,270,764		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under long-term debt	452,780			404,000
Payments on long-term debt	(68,410		)	(813		)
Debt issuance costs	(9,281		)	(8,958		)
Proceeds from issuance of common stock, net	2,123,344			930,315
Repurchase of common stock	(300		)	(213		)
Vesting of restricted stock units	—			(91		)
Net cash provided by financing activities	2,498,133			1,324,240
Net increase in cash and cash equivalents	109,168			228,678
Cash and cash equivalents at beginning of period	133,379			343,084
Cash and cash equivalents at end of period	$	242,547		$	571,762
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	49,565		$	42,909
Cash paid for income taxes	$	350		$	315
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate	$	8,144		$	(1,124	)
Additions (reductions) to oil and natural gas properties - change in capital accruals	$	57,014		$	(46,669	)
Additions to other property and equipment funded by capital lease borrowings	$	3,571		$	1,517
Common stock issued for oil and natural gas properties	$	1,183,501		$	—

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1. ORGANIZATION AND NATURE OF OPERATIONS

Parsley Energy, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company”) was formed on December 11, 2013, pursuant to the laws of the State of Delaware, succeeding the Company’s predecessor, which began operations in August 2008 when it acquired operator rights to wells producing from the Spraberry Trend in the Midland Basin. The Company is engaged in the acquisition and development of unconventional oil and natural gas reserves located in the Permian Basin, which is located in West Texas and Southeastern New Mexico.

NOTE 2. SUMMARY OF ACCOUNTING POLICIES

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

Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted in this Quarterly Report, as permitted by SEC rules and regulations. We believe the disclosures made in this Quarterly Report are adequate to make the information herein not misleading. We recommend that these condensed consolidated financial statements should be read in conjunction with the Company’s 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, necessary for a fair presentation of the results for the interim period. The results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the operating results of the entire fiscal year ending December 31, 2017.

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 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 asset retirement obligations;


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


•	impairment of undeveloped properties and other assets;


•	depreciation of property and equipment; and


•	valuation of commodity derivative instruments.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

Cash and Cash Equivalents

The Company considers all cash on hand, depository accounts held by banks, money market accounts, commercial paper and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

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

In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, Revenue Recognition, and most industry-specific guidance. ASU 2014-09 provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. In addition, new qualitative and quantitative disclosure requirements aim to enable financial statement users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the option of using either a full retrospective or modified retrospective approach to adopt the new standards. The Company anticipates adopting the standard using the modified retrospective approach and plans to implement the new guidance on January 1, 2018. The amended guidance is not expected to materially affect the Company’s condensed consolidated financial statements or notes to the condensed consolidated financial statements, but the Company does expect changes to the disclosures included in the notes to the condensed consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which modifies lessees’ recognition of lease assets and lease liabilities for those leases classified as operating leases under previous GAAP. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2018. Early adoption is permitted. The Company is evaluating the effect that ASU 2016-02 will have on its condensed consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), which requires that a statement of cash flows explain the total change during the period in cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statements of cash flows. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. Early adoption is permitted for any entity in any interim or annual period. The Company plans to implement the new guidance on January 1, 2018. The amended guidance is not expected to materially affect the Company’s condensed consolidated financial statements or notes to the condensed consolidated financial statement, with the exception of the presentation of restricted cash and restricted cash equivalents on the condensed consolidated statements of cash flows.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a framework which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after their effective date and no disclosures are required at transition. Early adoption is permitted for transactions when the acquisition date or disposal date occurs before the issuance date or effective date of the amendment, but only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company plans to implement the new guidance on January 1, 2018 and because the ASU will be implemented on a prospective basis, it will only affect the condensed consolidated financial statements and notes to the condensed consolidated financial statements in future periods.

In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, which amends the scope of modification accounting for share-based payment arrangements, provides guidance on the types of changes to the terms or conditions of share-based payment awards to which an entity would be required to apply modification accounting under ASC 718. The ASU is effective for annual reporting periods, including interim periods within those annual reporting periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period. The Company is evaluating the effect that ASU 2017-09 will have on its condensed consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

NOTE 3. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Instruments and Concentration of Risk

Objective and Strategy

The Company utilizes put spread options, three-way collars, commodity swap contracts and basis swap contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects.

Oil Production Derivative Activities

The Company’s material physical sales contracts governing its oil production are tied directly to, or are typically correlated with, WTI NYMEX oil prices. The Company uses put spread options, three-way collars and commodity swap contracts to manage oil price volatility and basis swap contracts to reduce basis risk between WTI NYMEX prices and the actual index prices at which the oil is sold.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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



Crude Options	Three Months Ending December 31, 2017			Year Ending December 31, 2018			Year Ending December 31, 2019
Put spreads
Purchased:
Puts⁽¹⁾
Notional (MBbl)	4,182			14,400			1,200
Weighted average strike price	$	50.96		$	50.52		$	50.00
Sold:
Puts⁽¹⁾
Notional (MBbl)	(4,182		)	(14,400		)	(1,200		)
Weighted average strike price	$	41.43		$	40.26		$	40.00

Three-way collars
Purchased:
Puts
Notional (MBbl)	—			10,200			3,000
Weighted average strike price	$	—		$	50.00		$	50.00
Sold:
Puts
Notional (MBbl)	—			(10,200		)	(3,000		)
Weighted average strike price	$	—		$	40.00		$	40.00
Calls
Notional (MBbl)	—			(10,200		)	(3,000		)
Weighted average strike price	$	—		$	73.13		$	80.40

Collars
Purchased:
Puts
Notional (MBbl)	368			1,095			—
Weighted average strike price	$	46.75		$	45.67		$	—
Sold:
Calls
Notional (MBbl)	(368		)	(1,095		)	—
Weighted average strike price	$	59.98		$	61.31		$	—

Swaps
Volume (MBbl)	46			183			—
Strike price ($/Bbl)	$	55.00		$	55.00		$	—

Basis swap contracts ⁽²⁾
Midland-Cushing index swap volume (MBbl)	1,536			4,158			—
Swap price ($/Bbl)	$	(1.00	)	$	(0.86	)	$	—

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



(1)	Excludes 2,439 notional MBbls with a fair value of $4.4 million related to amounts recognized under master netting agreements with derivative counterparties.
(2)	Represents swaps that fix the basis differentials between the index prices at which the Company sells its oil produced in the Permian Basin and the Cushing WTI 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 natural gas prices or regional index prices where the natural gas is sold. The Company uses three-way collars and commodity swap contracts to manage natural gas price volatility.

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



Natural Gas	Three Months Ending December 31, 2017			Year Ending December 31, 2018
Three-way collars
Purchased:
Puts
Notional (MMbtu)	1,425			2,400
Weighted average strike price	$	2.75		$	3.25
Sold:
Puts
Notional (MMbtu)	(1,425		)	(2,400		)
Weighted average strike price	$	2.36		$	2.60
Calls
Notional (MMbtu)	(1,425		)	(2,400		)
Weighted Average Strike Price	$	4.02		$	4.70

Swaps
Volume (MMbtu)	460			450
Strike price ($/MMbtu)	$	3.46		$	3.50

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 nine months ended September 30, 2017 and 2016 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Changes in fair value of derivative instruments	$	(60,450	)	(9,215		)	$	12,925		(74,583		)
Net derivative settlements	10,982			5,373			15,654			24,560
Net premiums realization on options that settled during the period	(12,487		)	5,216			(22,404		)	26,181
(Loss) gain on derivatives	$	(61,955	)	$	1,374		$	6,175		$	(23,842	)

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 14—Disclosures about Fair Value of Financial Instruments. The Company has agreements in place with all of its counterparties that allow for the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 the three and nine months ended September 30, 2017 and 2016, the Company did not receive or post any margins in connection with collateralizing its derivative positions.

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



	Gross Amount			Netting Adjustments			Net Exposure
September 30, 2017
Derivative assets with right of offset or master netting agreements	$	160,013		$	(4,351	)	$	155,662
Derivative liabilities with right of offset or master netting agreements	(144,632		)	4,351			(140,281		)

December 31, 2016
Derivative assets with right of offset or master netting agreements	$	66,417		$	(10,293	)	$	56,124
Derivative liabilities with right of offset or master netting agreements	(67,261		)	10,293			(56,968		)

Concentration of Credit Risk

The financial integrity of the Company’s exchange-traded contracts is assured by NYMEX through financial safeguards and transaction guarantees, and is therefore subject to nominal credit risk. Over-the-counter traded options expose the Company to counterparty credit risk. These over-the-counter options are entered into with a large multinational financial institution with an investment grade credit rating 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 September 30, 2017 and December 31, 2016 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 typically 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. The Company did not incur any losses due to counterparty nonperformance during the three and nine months ended September 30, 2017 or the year ended December 31, 2016.

Credit Risk Related Contingent Features in Derivatives

Certain commodity derivative instruments contain provisions that require the Company to either post additional collateral or immediately settle any outstanding liability balances upon the occurrence of a specified credit risk related event. These events, which are defined by the existing commodity derivative contracts, are primarily downgrades in the credit ratings of the Company and its affiliates. None of the Company’s commodity derivative instruments were in a net liability position with respect to any individual counterparty at September 30, 2017 or December 31, 2016.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 4. PROPERTY, PLANT AND EQUIPMENT

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



	September 30, 2017			December 31, 2016
Oil and natural gas properties:
Subject to depletion	$	3,923,734		$	2,376,712
Not subject to depletion
Incurred in 2017	2,930,596			—
Incurred in 2016	967,429			1,215,920
Incurred in 2015 and prior	328,644			470,785
Total not subject to depletion	4,226,669			1,686,705
Oil and natural gas properties, successful efforts method	8,150,403			4,063,417
Less accumulated depreciation, depletion and impairment	(732,690		)	(506,175		)
Total oil and natural gas properties, net	7,417,713			3,557,242
Other property, plant and equipment	108,932			73,382
Less accumulated depreciation	(21,370		)	(14,064		)
Other property, plant and equipment, net	87,562			59,318
Total property, plant and equipment, net	$	7,505,275		$	3,616,560

Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs and current drilling projects. At September 30, 2017 and December 31, 2016, the Company had excluded $4,226.7 million and $1,686.7 million, respectively, of capitalized costs from depletion.

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 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 $91.7 million and $238.8 million for the three and nine months ended September 30, 2017, respectively, and $63.9 million and $166.4 million for the three and nine months ended September 30, 2016, respectively. The Company had no exploratory wells in progress at September 30, 2017 or December 31, 2016.

NOTE 5. ACQUISITIONS AND DIVESTITURES

Acquisitions

During the three and nine months ended September 30, 2017, the Company incurred costs of $42.2 million and $168.1 million, respectively, related to the acquisition of leasehold acreage. During the three and nine months ended September 30, 2017, the Company reflected $40.4 million and $159.5 million, respectively, as part of costs not subject to depletion and $1.8 million and $8.6 million, respectively, as part of costs subject to depletion within its oil and natural gas properties.

In addition to the above-described acquisition of leasehold acreage, during the three and nine months ended September 30, 2017, the Company acquired, from unaffiliated individuals and entities, interests in certain oil and natural gas properties through a number of separate, individually negotiated transactions (including the Double Eagle Acquisition (as defined below) with respect to the nine months ended September 30, 2017) for total consideration of $0.9 million and $3,146.8 million, respectively. These acquisitions were accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the acquired assets and liabilities to be recorded at fair values as of the respective acquisition dates. The Company reflected ($2.6) million and $444.7 million, respectively, of the total consideration paid as part of its costs subject to depletion within its oil and natural gas properties and $3.5 million and $2,702.1 million, respectively, as unproved leasehold costs within its oil and natural gas properties for the three and nine months ended September 30, 2017. The $2.6 million negative adjustment to total consideration paid as part of the Company’ costs subject to depletion, recorded for the three months ended September 30, 2017, resulted from post-closing purchase price adjustments made in connection with the Double

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Eagle Acquisition. Excluding the Double Eagle Acquisition, the revenues and operating expenses attributable to these acquisitions during the three and nine months ended September 30, 2017 were not material.

On April 20, 2017, the Company and Parsley LLC completed the acquisition (the “Double Eagle Acquisition”) of all of the interests in Double Eagle Lone Star LLC, DE Operating LLC, and Veritas Energy Partners, LLC (which are currently named Parsley DE Lone Star LLC, Parsley DE Operating LLC, and Parsley Veritas Energy Partners, LLC, respectively) from Double Eagle Energy Permian Operating LLC (“DE Operating”), Double Eagle Energy Permian LLC (“DE Permian”), and Double Eagle Energy Permian Member LLC (together with DE Operating and DE Permian, “Double Eagle”), as well as certain related transactions with an affiliate of Double Eagle. The aggregate consideration for the Double Eagle Acquisition, following post-closing adjustments, was $2,579.1 million, which consisted of (i) approximately $1,394.7 million in cash and (ii) 39,848,518 units of PE Units and a corresponding 39,848,518 shares of the Company’s Class B common stock, par value $0.01 per share (“Class B Common Stock”). Of the aggregate consideration transferred, approximately $172.3 million in cash and approximately 4,921,557 PE Units (and a corresponding approximately 4,921,557 shares of Class B Common Stock) were deposited in an indemnity holdback escrow account.

The Company is in the process of identifying and determining the fair values of the assets acquired and liabilities assumed, pursuant to the Double Eagle Acquisition, and as a result, the estimates for fair value are subject to change. The Company anticipates certain changes, including, but not limited to, adjustments to working capital that are expected to be finalized prior to the measurement period’s expiration. The following table summarizes the preliminary estimated fair value of the assets acquired and liabilities assumed as a result of the Double Eagle Acquisition (in thousands):



Cash	$	2,469
Receivables	19,879
Derivatives	3,970
Proved oil and natural gas properties	353,000
Unproved oil and natural gas properties	2,252,147
Total assets acquired	2,631,465
Accounts payable	(44,969		)
Deferred tax liability	(7,381		)
Total liabilities assumed	(52,350		)
Estimated fair value of net assets acquired	$	2,579,115

The Company has included in its condensed consolidated statements of operations revenues of $48.7 million and earnings of $38.9 million for the period of April 20, 2017 to September 30, 2017 due to the Double Eagle Acquisition.

The Double Eagle Acquisition was deemed material for purposes of the following pro forma disclosures. The Double Eagle Acquisition was not included in the Company’s consolidated and combined results until its closing date.

The following unaudited pro forma information for the three and nine months ended September 30, 2017 and 2016 represents the results of the Company’s consolidated operations as if the Double Eagle Acquisition had occurred on January 1, 2016. This information is based on historical results of operations, adjusted for certain estimated accounting adjustments and does not purport to show the Company’s actual results of operations if the transaction would have occurred on January 1, 2016, nor is it necessarily indicative of future results. The financial information was derived from the Company’s unaudited historical consolidated and combined financial statements for the three and nine months ended September 30, 2017 and 2016 and Double

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Eagle’s unaudited interim financial statements from January 1, 2016 to April 20, 2017.



	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share data)	2017			2016			2017		2016
Revenues	$	241,021		$	141,606		$	674,680	$	326,635
Operating income	62,351			16,713			190,732		108
Net (loss) income	(15,728		)	(4,483		)	86,605		(58,932		)
Net (loss) income attributable to Parsley Energy, Inc. Stockholders	(13,729		)	(6,317		)	51,148		(43,055		)
Net (loss) income per common share:
Basic	$	(0.06	)	$	(0.03	)	$	0.21	$	(0.22	)
Diluted	$	(0.06	)	$	(0.03	)	$	0.21	$	(0.22	)

NOTE 6. ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal.

The following table summarizes the changes in the Company’s asset retirement obligations for the nine months ended September 30, 2017 (in thousands):



	September 30, 2017
Asset retirement obligations, beginning of period	$	11,392
Additional liabilities incurred	8,354
Accretion expense	597
Liabilities settled upon plugging and abandoning wells	(186		)
Disposition of wells	(247		)
Revision of estimates	37
Asset retirement obligations, end of period	$	19,947

NOTE 7. DEBT

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



	September 30, 2017			December 31, 2016
Revolving Credit Agreement	$	—		$	—
7.500% senior unsecured notes due 2022	—			61,846
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			—
Capital leases	5,249			3,752
Other debt	5,680			3,500
Total debt	1,510,929			1,119,098
Debt issuance costs on senior unsecured notes	(19,062		)	(14,388		)
Premium on senior unsecured notes	3,441			3,828
Less: current portion	(8,037		)	(67,214		)
Total long-term debt	$	1,487,271		$	1,041,324

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(Unaudited)

Redemption of 2022 Notes

On December 6, 2016, Parsley LLC and Parsley Finance Corp. (“Finance Corp.”), each a subsidiary of the Company, issued a conditional notice of redemption to redeem any and all of their 7.500% senior unsecured notes due 2022 (the “2022 Notes”) that remained outstanding following the consummation of a cash tender offer. In connection therewith, on January 5, 2017, Parsley LLC and Finance Corp. redeemed the $61.8 million aggregate principal amount of the 2022 Notes that remained outstanding and made a cash payment of $67.5 million to the remaining holders of the 2022 Notes, which included principal of $61.8 million, prepayment premium on the extinguishment of debt of $3.9 million and accrued interest of $1.8 million.

On January 6, 2017, the indenture, as supplemented, dated as of February 5, 2014, by and among Parsley LLC, Finance Corp., certain subsidiaries of Parsley LLC, as guarantors, and U.S. Bank National Association, as trustee, governing the 2022 Notes was satisfied and discharged. The 2022 Notes were scheduled to mature on February 15, 2022.

5.250% Senior Unsecured Notes due 2025

On February 13, 2017, Parsley LLC and Finance Corp. issued $450.0 million aggregate principal amount of 5.250% senior unsecured notes due 2025 (the “New 2025 Notes”) in an offering that was exempt from registration under the Securities Act (the “New 2025 Notes Offering”). The New 2025 Notes Offering resulted in net proceeds to the Company, after deducting initial purchaser discounts and commissions and offering expenses, of approximately $444.0 million.

Revolving Credit Agreement

On April 28, 2017, 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 Third Amendment (the “Third Amendment”) to the Company’s revolving credit agreement (as amended, the “Revolving Credit Agreement”). The Third Amendment, among other things, modified the terms of the Revolving Credit Agreement to (i) remove all anti-cash hoarding provisions, (ii) reduce the minimum mortgage and title coverage requirements from 90% to 85% of the total value of each of (a) Parsley LLC's and its subsidiaries’ proved oil and gas properties and (b) Parsley LLC’s and its subsidiaries’ proved, developed and producing reserves, in each case as evaluated in the most recent reserve report, and (iii) delete the applicable margin penalty, which increased the applicable margin by 0.5% with respect to alternate base rate loans and Eurodollar loans if the consolidated leverage ratio as of the last day of any fiscal quarter or fiscal year of Parsley LLC, as applicable, exceeded 3.50 to 1.00.

In addition, the Third Amendment increased the aggregate elected borrowing base commitments from $600.0 million to $1.0 billion and increased the borrowing base from $875.0 million to $1.4 billion. The Third Amendment also added Canadian Imperial Bank of Commerce, New York Branch; Capital One, National Association, Citibank, N.A.; PNC, National Association; and UBS AG, Stamford Branch as lenders under the Revolving Credit Agreement.

On May 22, 2017, 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 Fourth Amendment (the “Fourth Amendment”) to the Revolving Credit Agreement. The Fourth Amendment modified the terms of the Revolving Credit Agreement to (i) increase the lenders’ letter of credit commitment amount from $10.0 million to $30.0 million and (ii) increase the ceiling on lease payments during any consecutive 12-month period from 1.5% of the borrowing base to 2.5% of the borrowing base.

As of September 30, 2017, the borrowing base under the Revolving Credit Agreement was $1.4 billion, with a commitment level of $1.0 billion. There were no borrowings outstanding and $2.7 million in letters of credit outstanding as of September 30, 2017, resulting in availability of $997.3 million.

As of September 30, 2017, letters of credit under the Revolving Credit Agreement bear a 2.0% weighted average interest rate.

Covenant Compliance

The Revolving Credit Agreement and the indentures governing the 5.625% senior unsecured notes due 2027 (the “2027 Notes”), the New 2025 Notes, the 5.375% senior unsecured notes due 2025 (the “2025 Notes”), the 6.250% senior unsecured notes due 2024 (the “2024 Notes” and, together with the 2027 Notes, the 2025 Notes and the New 2025 Notes, the “Notes”) restrict the Company’s ability and the ability of certain of its subsidiaries to, among other things: (i) incur or guarantee

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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 dividends or other payments from its restricted subsidiaries to us; (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 September 30, 2017, the Company was in compliance with all required covenants under the Revolving Credit Agreement and each of the indentures governing the Notes.

Principal Maturities of Debt

Principal maturities of debt outstanding at September 30, 2017 are as follows (in thousands):



2017	$	1,823
2018	3,166
2019	5,393
2020	544
2021	3
Thereafter	1,500,000
Total	$	1,510,929

Interest Expense

The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2017 and 2016 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Cash payments for interest	$	34,463		$	21,668		$	49,565		$	42,909
Change in interest accrual	(12,478		)	(6,396		)	12,975			(4,828		)
Amortization of deferred loan origination costs	1,023			753			2,826			1,964
Write-off of deferred loan origination costs	—			155			—			329
Amortization of bond premium	(129		)	(234		)	(387		)	(617		)
Other interest income	(1,013		)	(385		)	(5,562		)	(803		)
Total interest expense, net	$	21,866		$	15,561		$	59,417		$	38,954

NOTE 8. EQUITY

Earnings per Share

Basic earnings per share (“EPS”) measures the performance of an entity over the reporting period. Diluted earnings per share 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 its outstanding 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 the three and nine months ended September 30, 2017 and 2016, Class B Common Stock was not recognized in dilutive earnings per share calculations as the effect would have been antidilutive. For the three months ended September 30, 2017 and the three and nine months ended September 30, 2016, restricted stock and restricted stock units were not recognized because the effect would have been antidilutive.

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The following table reflects the allocation of net income (loss) 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017		2016
Basic EPS (in thousands, except per share data)
Numerator:
Basic net (loss) income attributable to Parsley Energy, Inc. Stockholders	$	(13,333	)	$	(2,706	)	$	56,855	$	(43,437	)
Denominator:
Basic weighted average shares outstanding	246,518			173,241			237,725		156,018
Basic EPS attributable to Parsley Energy, Inc. Stockholders	$	(0.05	)	$	(0.02	)	$	0.24	$	(0.28	)
Diluted EPS
Numerator:
Net (loss) income attributable to Parsley Energy, Inc. Stockholders	(13,333		)	(2,706		)	56,855		(43,437		)
Diluted net (loss) income attributable to Parsley Energy, Inc. Stockholders	$	(13,333	)	$	(2,706	)	$	56,855	$	(43,437	)
Denominator:
Basic weighted average shares outstanding	246,518			173,241			237,725		156,018
Effect of dilutive securities:
Time-Based Restricted Stock and Time-Based Restricted Stock Units	—			—			1,060		—
Diluted weighted average shares outstanding ⁽¹⁾	246,518			173,241			238,785		156,018
Diluted EPS attributable to Parsley Energy, Inc. Stockholders	$	(0.05	)	$	(0.02	)	$	0.24	$	(0.28	)

(1)

As of September 30, 2017 and 2016, there were 640,062 and 453,863 shares, respectively, related to performance-based restricted stock units that could be converted to common shares in the future based on predetermined performance and market goals. These units were not included in the computation of EPS for the three and nine months ended September 30, 2017 and 2016, respectively, because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period.

Noncontrolling Interest

As a result of the Company’s equity offerings in January and February 2017, the Company’s ownership of Parsley LLC increased from 86.5% to 89.8% and the ownership of the other holders of PE Units (the “PE Unit Holders”) of Parsley LLC decreased from 13.5% to 10.2%. Subsequently, as a result of the consummation of the Double Eagle Acquisition, the Company’s ownership of Parsley LLC decreased from 89.8% to 78.4% and the PE Unit Holders’ ownership of Parsley LLC increased from 10.2% to 21.6%.

During the three months ended September 30, 2017, certain PE Unit Holders exercised their exchange right under the Second Amended and Restated Limited Liability Company Agreement of Parsley LLC (the “Parsley LLC Agreement”), collectively electing to exchange an aggregate of 1,201,375 PE Units (and a corresponding number of shares of Class B Common Stock) for an aggregate of 1,201,375 shares of the Company’s Class A common stock, par value $0.01 per share (“Class A Common Stock”) (the “Exchange”). 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 election notices. 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 three months ended September 30, 2017, the Company’s ownership in Parsley LLC increased from 78.4% to 78.8% and the ownership of the PE Unit Holders in Parsley LLC decreased from 21.6% to 21.2%.

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

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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 noncontrolling interest income (loss):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017			2016
	(In thousands)
Net (loss) income attributable to the noncontrolling interests of:
Parsley LLC	$	(1,353	)	$	799	$	22,604		$	(11,643	)
Pacesetter Drilling, LLC	(475		)	266		(536		)	260
Total net (loss) income attributable to noncontrolling interest	$	(1,828	)	$	1,065	$	22,068		$	(11,383	)

NOTE 9. STOCK-BASED COMPENSATION

In connection with the Company’s initial public offering (the “IPO”) in May 2014, the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan for employees, consultants, and directors of the Company who perform services for the Company. Refer to “Compensation Discussion and Analysis—Elements of Compensation—2014 Long-Term Incentive Plan” in the Company’s Proxy Statement filed on Schedule 14A for the 2017 Annual Meeting of Stockholders for additional information related to this equity based compensation plan.

Stock-based compensation expense recorded for each type of stock-based compensation award for the three and nine months ended September 30, 2017 and 2016 is as follows (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Time-base restricted stock	$	1,532	$	791	$	4,140	$	2,643
Time-base restricted stock units	1,947		1,526		5,825		4,151
Performance-based restricted stock units	1,691		999		4,665		2,672
Total stock-based compensation	$	5,170	$	3,316	$	14,630	$	9,466

Stock-based compensation is included in General and administrative expenses in the Company’s statement of operations included within this Quarterly Report. There was approximately $26.7 million of unamortized compensation expense relating to outstanding time-based restricted stock, time-based restricted stock units, and performance-based restricted stock units at September 30, 2017. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

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The following table summarizes the Company’s time-based restricted stock, time-based restricted stock unit, and performance-based restricted stock unit activity for the nine months ended September 30, 2017 (in thousands):



	Time-Based Restricted Stock			Time-Based Restricted Stock Units			Performance-Based Restricted Stock Units
Outstanding at January 1, 2017	601			1,046			454
Awards granted ⁽¹⁾	228			209			186
Vested	(37		)	(31		)	—
Forfeited	(1		)	(17		)	—
Outstanding at September 30, 2017	791			1,207			640

⁽¹⁾Weighted average grant date fair value	$	31.55		$	31.86		$	42.40

NOTE 10. INCOME TAXES

The Company is a corporation and is subject to U.S. federal income tax. The tax implications of the IPO and the Company’s concurrent corporate reorganization, and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying condensed consolidated financial statements. The effective combined U.S. federal and state income tax rate applicable to the Company for the nine months ended September 30, 2017 and 2016 was 24.5% and 28.4%, respectively. During the three and nine months ended September 30, 2017, the Company recognized an income tax benefit of $5.1 million and income tax expense of $25.5 million, respectively. During the three and nine months ended September 30, 2016, the Company recognized an income tax benefit of $1.3 million and $21.8 million, respectively. Total income tax expense for the three and nine months ended September 30, 2017 differed from amounts computed by applying the U.S. federal statutory tax rate of 35% due primarily to the impact of net income attributable to noncontrolling ownership interests as well as the impact of state income taxes and the reversal of a portion of the valuation allowance recorded in 2016.

As a result of the Company’s equity offerings in January and February 2017, the Company’s statutory rate related to certain tax and book basis timing differences increased by 1.2%, calculated by multiplying the 3.3% increase in the Company’s ownership of Parsley LLC by the Company’s federal tax rate of 35%. As a result, the Company recorded additional deferred tax liability of $13.1 million during the nine months ended September 30, 2017.

As a result of the issuance of 39,848,518 PE Units (and a corresponding number of shares of Class B Common Stock) in April 2017 pursuant to the Double Eagle Acquisition, the Company’s statutory rate related to certain tax and book basis timing differences decreased by 4.0%, calculated by multiplying the 11.4% decrease in the Company’s ownership of Parsley LLC by the Company’s federal tax rate of 35%. As a result, the Company recorded a decrease in deferred tax liability of $45.3 million during the nine months ended September 30, 2017.

As a result of the Exchange, the Company recorded an increase in deferred tax liability of $3.0 million during the three and nine months ended September 30, 2017.

The net effect of the Company’s equity offerings, issuance of PE Units and the Exchange was a reduction of deferred tax liability of $29.2 million during the nine months ended September 30, 2017.

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

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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 anticipated future tax benefits subject to 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 upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers and the portion of the Company’s payments under the TRA constituting imputed interest. As of September 30, 2017, there have been no payments associated with the TRA.

As a result of the Company being in a net income position and the expected utilization of deferred tax assets, the valuation allowance associated with the TRA of $24.2 million that was recorded in 2016 was reversed in the first quarter of 2017. The payable pursuant to the TRA is dependent on the realizability of the corresponding deferred tax assets. Accordingly, the payable pursuant to the TRA liability was increased by $20.5 million, which is 85% of the deferred tax asset that is expected to be realized. Due to the reduction in valuation allowance occurring during the first quarter of 2017, $20.5 million of the total increase to the TRA liability was recorded in Change in TRA liability in the Company’s condensed consolidated statements of operations and is included as an operating activity in the Company’s condensed consolidated statements of cash flows included in this Quarterly Report.

As of September 30, 2017 and December 31, 2016, the Company had recorded a TRA liability of $114.9 million and $94.3 million, respectively, for the estimated payments that will be made to the TRA Unit Holders who have exchanged shares of $135.1 million and $111.0 million, respectively, as a result of the increase in tax basis arising from such exchanges.

NOTE 11. 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 the 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 condensed 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 September 30, 2017 and December 31, 2016, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

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Contractual Obligations

The Company had no material changes in its contractual commitments and obligations from amounts listed under Note 12—Commitments and Contingencies in its Annual Report on Form 10-K for the year ended December 31, 2016, except as discussed below.

Firm Transportation and Processing Agreements. During the three months ended September 30, 2017, the Company entered into a contract that provides firm transportation and processing on one of the pipeline systems through which it transports or sells crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by the Company, purchased from third parties, and other third-party working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf. The Company’s condensed consolidated statements of operations reflect its share of these firm transportation and processing costs. This contract requires the Company to pay a deficiency fee if the Company fails to deliver the required volumes.

NOTE 12. RELATED PARTY TRANSACTIONS

Well Operations

During the three and nine months ended September 30, 2017 and 2016, 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 nine months ended September 30, 2017 totaled $0.3 million and $1.1 million, respectively. The revenues disbursed to such Related Party Working Interest Owners for the three and nine months ended September 30, 2016 totaled $0.5 million and $2.1 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. 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 nine months ended September 30, 2017, the Company incurred charges totaling $2.5 million and $8.1 million, respectively, for services performed by SPS for the Company’s well operations and drilling activities. During the three and nine months ended September 30, 2016, the Company incurred charges totaling $0.8 million and $3.1 million, respectively, for services performed by SPS for the Company’s well operations and drilling activities.

Lone Star Well Service, LLC

The Company makes purchases of equipment used in its drilling operations from Lone Star Well Service, LLC (“Lone Star”), which is controlled by SPS. During the three and nine months ended September 30, 2017, the Company incurred charges totaling $0.5 million and $5.5 million, respectively, for services performed by Lone Star for the Company’s well operations and drilling activities. During the three and nine months ended September 30, 2016, the Company incurred charges totaling $1.6 million and $4.4 million, respectively, for services performed by Lone Star for the Company’s well operations and drilling activities.

Davis, Gerald & Cremer, P.C.

During the three and nine months ended September 30, 2016, the Company incurred charges totaling $0.2 million and $0.3 million, respectively, for legal services from Davis, Gerald & Cremer, P.C., of which the Company’s director David H. Smith is a shareholder. There were no material charges incurred during the three and nine months ended September 30, 2017.

Exchange Right

In accordance with the terms of the Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange their PE Units (and a corresponding number of shares of the Class B Common Stock) for shares of Class A Common Stock at

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an exchange ratio of one share of Class A Common Stock for each PE Unit (and a corresponding share of Class B Common Stock) exchanged (subject to conversion rate adjustments for stock splits, stock dividends and reclassifications) or, if the Company or Parsley LLC so elects, cash. As a PE Unit Holder exchanges its PE Units, the Company’s interest in Parsley LLC will be correspondingly increased.

NOTE 13. SIGNIFICANT CUSTOMERS

For the nine months ended September 30, 2017 and 2016, each of the following purchasers accounted for more than 10% of the Company’s revenue:



	Nine Months Ended September 30,
	2017	2016
Shell Trading (US) Company	65%	35%
Targa Pipeline Mid-Continent, LLC	13%	13%
BML, Inc.	2%	18%
TransOil Marketing, LLC	1%	11%

The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

NOTE 14. 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.

Proved oil and natural gas properties. During the three and nine months ended September 30, 2017 and 2016, the Company did not recognize impairment charges, as the carrying amount of the assets exceeds the undiscounted future cash flows of the assets.

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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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):



	September 30, 2017
	Level 1		Level 2			Level 3		Total
Assets:
Money market funds	$	208,443	$	—		$	—	$	208,443
Commodity derivative instruments	—		155,662			—		155,662
Total assets	$	208,443	$	155,662		$	—	$	364,105

Liabilities:
Commodity derivative instruments	$	—	$	(140,281	)	$	—	$	(140,281	)
Total liabilities	$	—	$	(140,281	)	$	—	$	(140,281	)
Net asset	$	208,443	$	15,381		$	—	$	223,824



	December 31, 2016
	Level 1		Level 2			Level 3		Total
Assets:
Money market funds	$	49,230	$	—		$	—	$	49,230
Commodity derivative instruments	—		56,124			—		56,124
Total assets	$	49,230	$	56,124		$	—	$	105,354

Liabilities:
Commodity derivative instruments	$	—	$	(56,968	)	$	—	$	(56,968	)
Total liabilities	$	—	$	(56,968	)	$	—	$	(56,968	)
Net asset (liability)	$	49,230	$	(844	)	$	—	$	48,386

Money market funds in the preceding tables consist of money market funds included in cash and cash equivalents on the Company’s condensed consolidated balance sheet at September 30, 2017. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments. During the three and nine months ended September 30, 2017, income related to these investments was $0.8 million and $4.8 million, respectively, and is recorded on the Company’s condensed consolidated statements of operations as Interest expense, net. During the three and nine months ended September 30, 2016, income related to these investments was $0.5 million and $0.8 million, respectively, and is recorded on the Company’s condensed consolidated statements of operations as Interest expense, net.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 3—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.

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):



	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Current portion of long-term debt:
7.500% senior unsecured notes due 2022	$	—	$	—	$	61,846	$	65,737
Long-term debt:
6.250% senior unsecured notes due 2024	400,000		424,688		400,000		422,548
5.375% senior unsecured notes due 2025	650,000		664,872		650,000		654,531
5.250% senior unsecured notes due 2025	450,000		456,764		—		—
Revolving Credit Agreement	—		—		—		—

The fair values of the Notes were determined using the September 30, 2017 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 September 30, 2017, there are no indicators for change in the Company’s market spread.

Periodically, the Company invests in commercial paper with investment grade rated entities. The investments are carried at amortized cost and classified as held-to-maturity because the Company has the intent and ability to hold them until they mature. The net carrying value of held-to-maturity investments is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the investments. Income related to these investments is recorded on the Company’s condensed consolidated statements of operations as Interest expense, net.

The following table provides the components of the Company’s cash and cash equivalents as of the dates indicated (in thousands):



	Cash		Money Market Funds		Total
September 30, 2017	$	34,104	$	208,443	$	242,547
December 31, 2016	84,149		49,230		133,379

The Company has other financial instruments consisting primarily of accounts receivable, prepaid expenses, other current assets, accounts payable, accrued liabilities and capital leases that approximate their fair value due to the short-term nature of these instruments.

NOTE 15. SUBSEQUENT EVENTS

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

5.625% Senior Unsecured Notes due 2027

On October 11, 2017, Parsley LLC and Finance Corp. issued $700.0 million aggregate principal amount of the 2027 Notes in an offering that was exempt from registration under the Securities Act (the “2027 Notes Offering”). The 2027 Notes Offering resulted in net proceeds to the Company, after deducting the initial purchasers’ discount and offering expenses, of

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

approximately $691.9 million. The Company intends to use such net proceeds to fund a portion of its capital program and for general corporate purposes.

Fifth Amendment to Revolving Credit Facility

On October 11, 2017, 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 Fifth Amendment (the “Fifth Amendment”) to the Revolving Credit Agreement. The Fifth Amendment, among other things, modified the terms of the Revolving Credit Agreement to (i) increase the borrowing base under the Revolving Credit Agreement from $1.225 billion (to which it was reduced in connection with the closing of the 2027 Notes Offering) to $1.8 billion (although the aggregate elected commitments under the Revolving Credit Agreement remained at $1.0 billion), (ii) decrease the applicable margins for borrowings under the Revolving Credit Agreement to a range of (A) 1.5% to 2.5% for LIBOR based borrowings and (B) 0.5% to 1.5% for alternative base rate based borrowings, with the specific applicable margins determined by reference to borrowing base utilization, (iii) provide flexibility, subject to certain conditions, to enter into “reverse 1031 exchanges” under Section 1031 of the Internal Revenue Code of 1986, as amended, (iv) provide enhanced flexibility, subject to certain dollar limitations, to make investments in unrestricted subsidiaries and joint ventures and to make other investments, and (v) provide enhanced flexibility, subject to certain conditions, to dispose of oil and gas properties not evaluated in the reserve reports delivered to the lenders pursuant to the Revolving Credit Agreement.

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, 2016 (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” or the “Company”) was formed in December 2013, succeeding our predecessor, which began operations in August 2008 when it acquired operator rights to wells producing from the Spraberry Trend in the Midland Basin from Joe Parsley, a co-founder of Parker and Parsley Petroleum Company. We are a holding company whose sole material asset consists of 247,739,464 PE Units as of September 30, 2017. We are the managing member of Parsley Energy, LLC (“Parsley LLC”) and are responsible for all operational, management and administrative decisions of Parsley LLC, and we consolidate the financial results of Parsley LLC and its subsidiaries.

We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and Southeastern New Mexico and is comprised of three primary sub-areas: the Midland Basin, the Central Basin Platform and the Delaware Basin. These areas are 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 the Midland and Delaware Basins, where we focus predominantly on horizontal development drilling and expect to target various stacked pay intervals in the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline) and Atoka shales.

Our Properties

The following table sets forth information as of September 30, 2017 relating to our leasehold acreage:



	Developed Acreage		Undeveloped Acreage		Total Acreage
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	220,954	126,189	97,653	51,772	318,607	177,961
Delaware Basin	30,540	28,574	26,473	22,608	57,013	51,182
Total	251,494	154,763	124,126	74,380	375,620	229,143

In addition to the leasehold acreage described above, as of September 30, 2017, we held mineral rights in 33,221 acres, with an average royalty interest of 20.9%. These mineral rights and associated royalty interests boost our net revenue interest in the applicable properties.

The majority of 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 September 30, 2017, we operated the following wells:



	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	997	749.7	212	194.8	1,209	944.5
Delaware Basin	14	13.5	41	38.4	55	51.9
Total	1,011	763.2	253	233.2	1,264	996.4

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As of September 30, 2017, we held an interest in 1,730 gross (1,087.5 net) wells, including wells that we did not operate. As of September 30, 2017, we owned an immaterial number of productive wells related to the production of natural gas.

Since commencing our horizontal drilling program in 2013 through September 30, 2017, we have drilled and completed 203 gross (190.1 net) horizontal wells in the Midland Basin and 24 gross (22.6 net) horizontal wells in the Delaware Basin. The table below summarizes the horizontal wells drilled and completed in the periods indicated:



	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
Area	Gross	Net	Gross	Net
Midland Basin	27	26.9	67	63.1
Delaware Basin	9	7.9	18	16.8
Total	36	34.8	85	79.9

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;


•	completions activities; 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Oil sales	83	%	86	%	84	%	85	%
Natural gas sales	6	%	6	%	6	%	7	%
Natural gas liquids sales	11	%	8	%	10	%	8	%

Other revenues include fees charged by certain of our subsidiaries, Pacesetter Drilling, LLC (“Pacesetter”) and Parsley Minerals, LLC, to third parties for drilling services and surface use in the normal course of business. In addition, other revenues include salt water and gathering system income.

Production Volumes

The following table presents historical production volumes for our properties for the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Oil (MBbls)	4,342	2,669	11,653	6,557
Natural gas (MMcf)	6,265	3,553	16,105	9,651
Natural gas liquids (MBbls)	1,194	695	3,063	1,686
Total (MBoe)	6,581	3,956	17,402	9,852
Average net production (Boe/d)	71,534	43,000	63,744	35,956

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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 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.

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 natural gas or NGLs prices.

The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and differentials to the average of those benchmark prices for the periods indicated:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Oil
NYMEX WTI High	$	52.22		$	48.99		$	54.45		$	51.23
NYMEX WTI Low	$	44.23		$	39.51		$	42.53		$	26.21
Differential to Average NYMEX WTI	$	(2.43	)	$	(2.02	)	$	(1.58	)	$	0.30

Natural Gas
NYMEX Henry Hub High	$	3.15		$	3.06		$	3.42		$	3.06
NYMEX Henry Hub Low	$	2.77		$	2.55		$	2.56		$	1.64
Differential to Average NYMEX Henry Hub	$	(0.47	)	$	(0.43	)	$	(0.44	)	$	(0.29	)

NGLs
NYMEX WTI High	$	52.22		$	48.99		$	54.45		$	51.23
NYMEX WTI Low	$	44.23		$	39.51		$	42.53		$	26.21
Differential to Average NYMEX	$	(26.00	)	$	(28.75	)	$	(27.50	)	$	(24.00	)

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for a portion of our production, with an emphasis on our oil production. By removing a significant 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 those periods. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our oil, natural gas or NGLs production.

The volumes and terms of our derivative instruments as of September 30, 2017 were as follows:



Description and Production Period	VOLUME (MBbls)	SHORT PUT PRICE ($/Bbl)		LONG PUT PRICE ($/Bbl)		SHORT CALL PRICE ($/Bbl)	PRICE
Crude Oil Put Spreads:
Oct 2017 - Dec 2017	300	$	40.00	$	52.50
Oct 2017 - Dec 2017	132	$	40.00	$	45.00
Oct 2017 - Dec 2017	1,500	$	42.50	$	52.50
Oct 2017 - Dec 2017	375	$	40.00	$	47.50
Oct 2017 - Dec 2017	225	$	40.00	$	55.00

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Description and Production Period	VOLUME (MBbls)	SHORT PUT PRICE ($/Bbl)		LONG PUT PRICE ($/Bbl)		SHORT CALL PRICE ($/Bbl)		PRICE
Oct 2017 - Dec 2017	750	$	40.00	$	50.00
Oct 2017 - Dec 2017	300	$	42.50	$	55.00
Oct 2017 - Dec 2017	600	$	42.50	$	47.50
Jan 2018 - Mar 2018	600	$	42.50	$	55.00
Jan 2018 - Mar 2018	900	$	40.00	$	52.50
Jan 2018 - Jun 2018	600	$	37.50	$	47.50
Jan 2018 - Jun 2018	1,200	$	42.50	$	52.50
Jan 2018 - Jun 2018	600	$	40.00	$	50.00
Jan 2018 - Dec 2018	3,000	$	40.00	$	50.00
Apr 2018 - Jun 2018	600	$	45.00	$	55.00
Apr 2018 - Jun 2018	900	$	40.00	$	50.00
Jul 2018 - Sept 2018	300	$	40.00	$	50.00
Jul 2018 - Dec 2018	4,200	$	40.00	$	50.00
Jul 2018 - Dec 2018	900	$	37.50	$	47.50
Oct 2018 - Dec 2018	600	$	40.00	$	50.00
Jan 2019 - Jun 2019	1,200	$	40.00	$	50.00
Total	19,782

Crude Oil Three-Way Collars:
Jan 2018 - Jun 2018	1,500	$	40.00	$	50.00	$	60.00
Jan 2018 - Dec 2018	2,400	$	40.00	$	50.00	$	74.75
Jan 2018 - Dec 2018	2,400	$	40.00	$	50.00	$	74.00
Apr 2018 - Jun 2018	600	$	40.00	$	50.00	$	77.10
Jul 2018 - Dec 2018	600	$	40.00	$	50.00	$	76.93
Jul 2018 - Dec 2018	1,200	$	40.00	$	50.00	$	76.80
Jul 2018 - Dec 2018	1,500	$	40.00	$	50.00	$	76.25
Jan 2019 - Dec 2019	1,800	$	40.00	$	50.00	$	80.00
Jan 2019 - Dec 2019	1,200	$	40.00	$	50.00	$	81.00
Total	13,200

Crude Oil Collars:
Oct 2017 - Dec 2017	46			$	47.00	$	56.45
Oct 2017 - Dec 2017	92			$	45.00	$	64.25
Oct 2017 - Dec 2017	92			$	49.00	$	59.00
Oct 2017 - Dec 2017	92			$	47.00	$	58.00
Oct 2017 - Dec 2018	229			$	45.00	$	60.85
Jan 2018 - Dec 2018	365			$	47.00	$	59.40
Jan 2018 - Dec 2018	183			$	45.00	$	60.00
Jan 2018 - Dec 2018	365			$	45.00	$	64.10
Total	1,463

Crude Oil Swaps:
Oct 2017 - Dec 2018	229							$	55.00

Crude Oil Basis Swaps:
Oct 2017 - Dec 2017	276							$	(0.40	)
Oct 2017 - Dec 2017	276							$	(0.45	)
Oct 2017 - Dec 2017	92							$	(0.90	)
Oct 2017 - Dec 2017	46							$	(0.95	)

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Description and Production Period	VOLUME (MBbls)	SHORT PUT PRICE ($/Bbl)	LONG PUT PRICE ($/Bbl)	SHORT CALL PRICE ($/Bbl)	PRICE
Oct 2017 - Dec 2017	90				$	(1.65	)
Oct 2017 - Dec 2017	240				$	(1.65	)
Oct 2017 - Dec 2017	90				$	(1.60	)
Oct 2017 - Dec 2017	150				$	(1.70	)
Oct 2017 - Dec 2018	1,143				$	(0.80	)
Oct 2017 - Dec 2018	229				$	(1.00	)
Jan 2018 - Dec 2018	360				$	(0.95	)
Jan 2018 - Dec 2018	183				$	(1.30	)
Jan 2018 - Dec 2018	840				$	(0.85	)
Jan 2018 - Dec 2018	600				$	(0.50	)
Jan 2018 - Dec 2018	1,080				$	(1.00	)
Total	5,694



Description and Production Period	VOLUME (MMbtu)	SHORT PUT PRICE ($/MMbtu)		LONG PUT PRICE ($/MMbtu)		SHORT CALL PRICE ($/MMbtu)		PRICE
Natural Gas Three-Way Collars:
Oct 2017 - Dec 2017	900	$	2.40	$	2.75	$	4.00
Oct 2017 - Dec 2017	225	$	2.35	$	2.75	$	4.05
Oct 2017 - Dec 2017	300	$	2.25	$	2.75	$	4.05
Jan 2018 - Mar 2018	2,400	$	2.60	$	3.25	$	4.70
Total	3,825

Natural Gas Swaps:
Oct 2017	155							$	3.39
Nov 2017 - Mar 2018	755							$	3.50
Total	910

We will recognize the following losses in the line item 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):



Q4 2017	$	(14,644	)
Q1 2018	(19,577		)
Q2 2018	(18,020		)
Q3 2018	(18,313		)
Q4 2018	(19,573		)
Q1 2019	(4,200		)
Q2 2019	(4,200		)
Q3 2019	(1,500		)
Q4 2019	(1,500		)
Total	$	(101,527	)

Impairment of Oil and Natural Gas Properties

Proved oil and natural gas properties are reviewed for impairment quarterly 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.

As a result of suppressed commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and natural gas properties for impairment. During the three and nine months ended September 30, 2017 and 2016, we did not recognize an impairment of our proved oil and natural gas properties. At September 30, 2017, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and natural gas properties by an average of 142% per field.

The key assumptions used to determine the undiscounted future cash flows include, but are not limited to, future commodity prices, based on five-year WTI futures price index for oil and NGLs and five-year Henry Hub futures price index for natural gas, 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 September 30, 2016 to September 30, 2017. Future commodity pricing for oil and NGLs is based on five-year WTI futures prices, which increased from September 30, 2016 to September 30, 2017, and on five-year Henry Hub futures prices, which increased from September 30, 2016 to September 30, 2017. In terms of the increase in value of undiscounted cash flows from September 30, 2016 to September 30, 2017, the effect of the increase in pricing has been complemented by 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 there could be 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 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 our 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 September 30, 2017, 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:

Recent Transactions

Private Placement of Senior Notes

On October 11, 2017, Parsley LLC and Parsley Finance Corp., a wholly owned subsidiary of Parsley LLC (“Finance Corp.”), issued $700.0 million aggregate principal amount of 5.625% senior unsecured notes due 2027 (the “2027 Notes”) in an offering that was exempt from registration under the Securities Act (the “2027 Notes Offering”). The 2027 Notes Offering resulted in net proceeds to us, after deducting the initial purchasers’ discounts and offering expenses, of approximately $691.9 million. We intend to use such net proceeds to fund a portion of our capital program and for general corporate purposes.

Fifth Amendment to the Revolving Credit Agreement

On October 11, 2017, we, Parsley LLC, each of the guarantors thereto, Wells Fargo Bank, National Association, as administrative agent, and the other lenders party thereto entered into the Fifth Amendment (the “Fifth Amendment”) to our revolving credit agreement (as amended, the “Revolving Credit Agreement”). The Fifth Amendment, among other things, modified the terms of the Revolving Credit Agreement to (i) increase the borrowing base under the Revolving Credit

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Agreement from $1.225 billion (to which it was reduced in connection with the closing of the 2027 Notes Offering) to $1.8 billion (although the aggregate elected commitments under the Revolving Credit Agreement remained at $1.0 billion), (ii) decrease the applicable margins for borrowings under the Revolving Credit Agreement to a range of (A) 1.5% to 2.5% for LIBOR based borrowings and (B) 0.5% to 1.5% for alternative base rate based borrowings, with the specific applicable margins determined by reference to borrowing base utilization, (iii) provide flexibility, subject to certain conditions, to enter into “reverse 1031 exchanges” under Section 1031 of the Internal Revenue Code of 1986, as amended, (iv) provide enhanced flexibility, subject to certain dollar limitations, to make investments in unrestricted subsidiaries and joint ventures and to make other investments, and (v) provide enhanced flexibility, subject to certain conditions, to dispose of oil and gas properties not evaluated in the reserve reports delivered to the lenders pursuant to the Revolving Credit Agreement.

Drilling Activity

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Capital expenditures	$	306,788	$	91,924	$	790,193	$	338,407

Our capital expenditures for drilling, completions and infrastructure (including facility buildout) were $496.0 million for the year ended December 31, 2016, of which our aggregate drilling and completion expenses were $401.6 million and our infrastructure and other expenditures were $94.4 million. Of the total, $53.2 million was associated with drilling, completions and facility buildout for proved undeveloped reserves.

The amount and timing of our future capital expenditures is largely discretionary and within our control. We could choose to defer a portion of 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.

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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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Production revenues (in thousands):
Oil sales	$	198,865	$	112,705	$	546,676	$	255,865
Natural gas sales	15,601		8,457		41,051		19,834
Natural gas liquids sales	26,547		10,770		64,296		24,811
Total revenues	$	241,013	$	131,932	$	652,023	$	300,510

Average realized prices ⁽¹⁾:
Oil, without realized derivatives (per Bbls)	$	45.80	$	42.23	$	46.91	$	39.02
Oil, with realized derivatives (per Bbls)	45.51		46.19		46.38		46.76
Natural gas, without realized derivatives (per Mcf)	2.49		2.38		2.55		2.06
Natural gas, with realized derivatives (per Mcf)	2.45		2.38		2.52		2.06
Natural gas liquids (per Bbls)	22.23		15.50		20.99		14.72
Average price per Boe, without realized derivatives	36.62		33.35		37.47		30.50
Average price per Boe, with realized derivatives	36.39		36.03		37.08		35.65

Production:
Oil (MBbls)	4,342		2,669		11,653		6,557
Natural gas (MMcf)	6,265		3,553		16,105		9,651
Natural gas liquids (MBbls)	1,194		695		3,063		1,686
Total (MBoe)	6,581		3,956		17,402		9,852

Average daily production volume:
Oil (Bbls)	47,196		29,011		42,685		23,931
Natural gas (Mcf)	68,098		38,620		58,993		35,223
Natural gas liquids (Bbls)	12,978		7,554		11,220		6,153
Total (Boe)	71,534		43,000		63,744		35,956



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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Average realized oil price ($/Bbl)	$	45.80		$	42.23		$	46.91		$	39.02
Average NYMEX ($/Bbl)	$	48.23		$	44.25		$	48.49		$	38.72
Differential to NYMEX	$	(2.43	)	$	(2.02	)	$	(1.58	)	$	0.30
Average realized oil price as a percentage of average NYMEX oil price	95		%	95		%	97		%	101		%
Average realized natural gas price ($/Mcf)	$	2.49		$	2.38		$	2.55		$	2.06
Average NYMEX ($/Mcf)	$	2.96		$	2.81		$	2.99		$	2.35
Differential to NYMEX	$	(0.47	)	$	(0.43	)	$	(0.44	)	$	(0.29	)
Average realized natural gas price as a percentage of average NYMEX gas price	84		%	85		%	85		%	88		%
Average realized NGLs price ($/Bbl)	$	22.23		$	15.50		$	20.99		$	14.72
Average NYMEX ($/Bbl)	$	48.23		$	44.25		$	48.49		$	38.72
Differential to NYMEX	$	(26.00	)	$	(28.75	)	$	(27.50	)	$	(24.00	)
Average realized NGLs price as a percentage of average NYMEX oil price	46		%	35		%	43		%	38		%

Oil, natural gas and NGLs revenues. Our oil, natural gas and NGLs revenues increased by $109.1 million, or 83%, to $241.0 million for the three months ended September 30, 2017 from $131.9 million for the three months ended September 30, 2016.

As shown in the following tables, from the three months ended September 30, 2016 to the three months ended September 30, 2017, the net dollar effect of the increase in oil, natural gas, and NGLs prices was $24.2 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs was $84.8 million.



	Change in prices		Production volumes	Total net dollar effect of change
Effect of change in price:			(in thousands)	(in thousands)
Oil (per Bbls)	$	3.57	4,342	$	15,514
Natural gas (per Mcf)	0.11		6,265	689
Natural gas liquids (per Bbls)	6.74		1,194	8,044
Total revenues due to change in price				$	24,247



	Change in production volumes	Prior period average prices		Total net dollar effect of change
Effect of change in production volumes:	(in thousands)			(in thousands)
Oil (MBbls)	1,673	$	42.23	$	70,646
Natural gas (MMcf)	2,712	2.38		6,455
Natural gas liquids (MBbls)	499	15.50		7,733
Total revenues due to change in production volumes				$	84,834

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Our oil, natural gas and NGLs revenues increased by $351.5 million, or 117%, to $652.0 million for the nine months ended September 30, 2017 from $300.5 million for the nine months ended September 30, 2016.

As shown in the following tables, from the nine months ended September 30, 2016 to the nine months ended September 30, 2017, the net dollar effect of the increase in oil, natural gas and NGLs prices was $119.1 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs was approximately $232.4 million.



	Change in prices		Production volumes	Total net dollar effect of change
Effect of change in price:			(in thousands)	(in thousands)
Oil (per Bbls)	$	7.89	11,653	$	91,956
Natural gas (per MMcf)	0.49		16,105	7,953
Natural gas liquids (per Bbls)	6.27		3,063	19,221
Total revenues due to change in price				$	119,130



	Change in production volumes	Prior period average prices		Total net dollar effect of change
Effect of change in production volumes:	(in thousands)			(in thousands)
Oil (MBbls)	5,096	$	39.02	$	198,855
Natural gas (MMcf)	6,454	2.06		13,264
Natural gas liquids (MBbls)	1,377	14.72		20,264
Total revenues due to change in production volumes				$	232,383

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Operating expenses

The following table summarizes our expenses for the periods indicated:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Operating expenses (in thousands):
Lease operating expenses	$	29,525	$	16,407	$	76,783	$	44,509
Production and ad valorem taxes	14,808		8,391		37,367		18,993
Depreciation, depletion and amortization	94,819		65,741		247,104		171,113
General and administrative expenses ⁽¹⁾	33,573		24,695		89,376		61,301
Exploration costs	88		3,113		5,293		12,779
Acquisition costs	2,449		440		10,969		926
Accretion of asset retirement obligations	268		190		597		575
Other operating expenses	2,419		1,220		7,205		3,767
Total operating expenses	$	177,949	$	120,197	$	474,694	$	313,963

Expense per Boe:
Lease operating expenses	$	4.49	$	4.15	$	4.41	$	4.52
Production and ad valorem taxes	2.25		2.12		2.15		1.93
Depreciation, depletion and amortization	14.41		16.62		14.20		17.37
General and administrative expenses	5.10		6.24		5.14		6.22
Exploration costs	0.01		0.79		0.30		1.30
Acquisition costs	0.37		0.11		0.63		0.09
Accretion of asset retirement obligations	0.04		0.05		0.03		0.06
Other operating expenses	0.37		0.31		0.41		0.38
Total operating expenses per Boe	$	27.04	$	30.39	$	27.27	$	31.87


(1)	General and administrative expenses include stock-based compensation expense of $5.2 million and $14.6 million for the three and nine months ended September 30, 2017, respectively, as compared to $3.3 million and $9.5 million for the three and nine months ended September 30, 2016, respectively.

Lease operating expenses. Lease operating expenses were $29.5 million and $76.8 million for the three and nine months ended September 30, 2017, respectively, as compared to $16.4 million and $44.5 million for the three and nine months ended September 30, 2016. These increases are primarily due to the increase in number of our operated and non-operated wells during 2017.

On a per Boe basis, lease operating expenses increased to $4.49 during the three months ended September 30, 2017 from $4.15 during the three months ended September 30, 2016. This increase in lease operating expenses per Boe is partially attributable to increased workover costs and an infusion of vertical production and lifting costs on non-operated wells, all of which are associated with acquired wells. The increase is offset by a 66% increase in production during the same period.

On a per Boe basis, lease operating expenses decreased to $4.41 during the nine months ended September 30, 2017 from $4.52 during the nine months ended September 30, 2016. This decrease in lease operating expenses per Boe is partially attributable to a greater portion of our production coming from horizontal wells, which generally results in lower per Boe costs, in addition to a 77% increase in production during the same period.

Production and ad valorem taxes. Production and ad valorem taxes were $14.8 million and $37.4 million for the three and nine months ended September 30, 2017, respectively, as compared to $8.4 million and $19.0 million for the three and nine months ended September 30, 2016, respectively. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior period commodity prices, whereas production taxes are based on current period commodity prices.

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Overall, for the three and nine months ended September 30, 2017, compared to the same respective periods in 2016, production taxes increased by approximately $5.7 million and $18.0 million, respectively, due to increased production during the periods and ad valorem taxes increased $0.7 million and $0.4 million, respectively, reflecting increased property assessments.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $94.8 million and $247.1 million for the three and nine months ended September 30, 2017, respectively, as compared to $65.7 million and $171.1 million for the three and nine months ended September 30, 2016.

These increases are attributable to a $1,698.9 million increase in costs subject to depletion as of September 30, 2017 as compared to September 30, 2016 and 66% and 77% increases in production during the three and nine months ended September 30, 2017, respectively, as compared to the same respective periods in 2016. These increases were offset by a 99% increase in total proved reserves and a 103% increase in proved developed reserves as of September 30, 2017, as compared to September 30, 2016.

On a per Boe basis, DD&A expense decreased to $14.41 for the three months ended September 30, 2017 from $16.62 during the three months ended September 30, 2016, and decreased to $14.20 for the nine months ended September 30, 2017 from $17.37 during the nine months ended September 30, 2016, in each case primarily due to the increase in production volumes and the increase in reserves discussed above.

General and administrative expenses. General and administrative expenses were $33.6 million and $89.4 million for the three and nine months ended September 30, 2017, respectively, and $24.7 million and $61.3 million for the three and nine months ended September 30, 2016, respectively. These increases were primarily due to higher payroll and stock-based compensation expenses associated with the hiring of additional employees to manage our growing asset base, recent acquisitions and increased production. General and administrative expenses per Boe were $5.10 and $5.14 for the three and nine months ended September 30, 2017, respectively, as compared to $6.24 and $6.22 for the three and nine months ended September 30, 2016, respectively.

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017		2016
Unproved leasehold amortization	$	143		$	203	$	562	$	356
Geological and geophysical costs	(55		)	1,233		3,661		3,292
Idle drilling rig fees	—			1,187		1,070		3,117
Leasehold abandonments	—			490		—		6,014
Total exploration costs	$	88		$	3,113	$	5,293	$	12,779

We recognized leasehold amortization expense of $0.1 million and $0.6 million during the three and nine months ended September 30, 2017, respectively, as compared to $0.2 million and $0.4 million during the three and nine months ended September 30, 2016, respectively. In each case, these expenses are related to the amortization of unproved leasehold costs.

Our geological and geophysical (“G&G”) costs consist of the costs of acquiring and processing seismic data, geophysical data and core analysis, primarily relating to increased geoscientific analysis of our acreage.

Exploration costs include idle drilling rig fees of that are not chargeable to our joint operations. The applicable drilling rig contract expired on March 31, 2017, resulting in a decrease in idle drilling rig fees during the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016.

During the three and nine months ended September 30, 2016, we recognized leasehold abandonment expenses of approximately $0.5 million and $6.0 million, respectively, which primarily relate to acreage expirations on rights to certain formations in various counties. There was no such activity for the three and nine months ended September 30, 2017.

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Acquisition costs. During the three and nine months ended September 30, 2017, we incurred $2.4 million and $11.0 million, respectively, of acquisition costs. During the three and nine months ended September 30, 2016, we incurred $0.4 million and $0.9 million, respectively, of acquisition costs. Acquisition costs include legal and other due diligence fees paid associated with the acquisitions (which primarily relate to the Double Eagle Acquisition during the three and nine months ended September 30, 2017) described in Note 5—Acquisitions and Divestitures to our condensed consolidated financial statements included elsewhere in this Quarterly Report.

Other operating expenses. In the normal course of business of Pacesetter, we incurred other operating expenses of $2.4 million and $7.2 million during the three and nine months ended September 30, 2017, respectively, as compared to $1.2 million and $3.8 million, respectively, during the three and nine months ended September 30, 2016.

Other income (expense)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Other income (expense) (in thousands):
Interest expense, net	$	(21,866	)	$	(15,561	)	$	(59,417	)	$	(38,954	)
Loss on sale of property	—			—			—			(119		)
Loss on early extinguishment of debt	—			—			(3,891		)	—
(Loss) gain on derivatives	(61,955		)	1,374			6,175			(23,842		)
Change in TRA liability	—			—			(20,549		)	—
Other income (expense)	508			(1,073		)	1,281			(1,605		)
Total other expense, net	$	(83,313	)	$	(15,260	)	$	(76,401	)	$	(64,520	)

Interest expense, net. Interest expense, net for the three and nine months ended September 30, 2017 was $21.9 million and $59.4 million, respectively, as compared to $15.6 million and $39.0 million, respectively, for the three and nine months ended September 30, 2016. These increases are a result of increased weighted average debt outstanding, as discussed in Note 7—Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report.

Loss on sale of property. We recognized a $0.1 million loss on the sale of property during the nine months ended September 30, 2016 attributable to purchase price adjustments from acquisitions that closed during prior periods. There was no such activity for the three and nine months ended September 30, 2017 or the three months ended September 30, 2016.

Loss on early extinguishment of debt. The Company recorded a $3.9 million loss on early extinguishment of debt during the nine months ended September 30, 2017 due to the redemption of the 7.500% senior unsecured notes due 2022 as discussed in Note 7—Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report. There was no such activity for the three months ended September 30, 2017 or the three and nine months ended September 30, 2016.

(Loss) gain on derivatives. We recognized a loss on derivatives of $62.0 million and a gain of derivatives $6.2 million, respectively during the three and nine months ended September 30, 2017, as compared to a gain on derivatives of $1.4 million and a loss on derivatives $23.8 million, respectively, during the same respective periods in 2016. The change during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016 is primarily a result of higher commodity prices, which decrease the value of our derivative portfolio. The change during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 is primarily a result of lower commodity prices, which increase the value of our derivative portfolio.

Change in TRA liability. The Company recorded a $20.5 million expense during the nine months ended September 30, 2017 associated with an increase in the TRA liability resulting from the reversal of the valuation allowance recorded during 2016. There was no such activity for the three months ended September 30, 2017 or the three and nine months ended September 30, 2016.

Other income (expense). Other income was $0.5 million and $1.3 million for the three and nine months ended September 30, 2017, respectively, as compared to other expense of $1.1 million and $1.6 million for the three and nine months ended September 30, 2016, respectively. The increase for the three months ended September 30, 2017, as compared to the same respective period in 2016 is primarily attributable to the sale or auction of certain inventory items for $1.3 million as well as a

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$0.3 million increase in income from our equity investment in Spraberry Production Services, LLC (“SPS”). The increase in other income for the nine months ended September 30, 2017, as compared to the same respective period in 2016, is primarily related to the sale or auction of certain inventory items for $1.3 million as well as a $1.6 million increase in income from our equity investment in SPS.

Income Tax Benefit (Expense)

During the three and nine months ended September 30, 2017, we recognized income tax benefits of $5.1 million and income tax expense of $25.5 million, respectively. During the three and nine months ended September 30, 2016, we recognized income tax benefits of $1.3 million and $21.8 million, respectively. These changes were attributable to the changes in our results of operations, discussed above, as well as the impact of net income attributable to noncontrolling ownership interests, the impact of state income taxes and the reversal of a valuation allowance that was recorded in 2016.

Capital Requirements and Sources of Liquidity

For the nine months ended September 30, 2017, our aggregate drilling, completions and infrastructure capital expenditures, including facilities, were $790.2 million. During the year ended December 31, 2016, our aggregate drilling, completions and infrastructure (including facility buildout) capital expenditures were $496.0 million. These capital expenditure totals exclude acquisitions.

Our 2017 budget for capital development expenditures is approximately $1,000.0 million to $1,150.0 million. This estimate includes $160.0 million to $190.0 million related to infrastructure and other expenditures and $840.0 million to $960.0 million for drilling and completions, $262.9 million of which is associated with drilling, completions and facility buildout for proved undeveloped reserves as of December 31, 2016. For the prior year period, our aggregate drilling and completion expenditures were $401.6 million and our infrastructure (including facility buildout) and other expenditures were $94.4 million, for a total of $496.0 million. Of the total, $53.2 million was associated with drilling, completions and facility buildout for proved undeveloped reserves. The amount and timing of 2017 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2017 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 2017, 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 2017. However, as more fully described below, 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. As of September 30, 2017, our liquidity was as follows (in millions):



Cash and cash equivalents	$	242.5
Revolving Credit Agreement availability	997.3
Liquidity	$	1,239.8

Pro forma for the 2027 Notes Offering our liquidity as of September 30, 2017 was approximately $1,931.7 million.

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, 2016 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 2017 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 traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt or equity securities or other means. There is no assurance that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital

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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):



	Nine Months Ended September 30,
	2017			2016
Net cash provided by operating activities	$	491,263		$	175,202
Net cash used in investing activities	(2,880,228		)	(1,270,764		)
Net cash provided by financing activities	2,498,133			1,324,240

Cash flows provided by operating activities. Net cash provided by operating activities was approximately $491.3 million and $175.2 million for the nine months ended September 30, 2017 and 2016, respectively. Net cash provided by operating activities increased from the period ending September 30, 2016 to September 30, 2017, primarily due to a $353.7 million increase in total revenues, offset by a $90.9 million increase in cash based operating expenses, including lease operating expenses, production and ad valorem taxes, cash general and administrative expenses, exploration costs and acquisition costs, as well as a decrease in funds used to satisfy working capital obligation.

Cash flows used in investing activities. Net cash used in investing activities was approximately $2,880.2 million and $1,270.8 million for the nine months ended September 30, 2017 and 2016, respectively. The increased amount of cash used in investing activities was due primarily to the $1,266.5 million increase in acquisition costs and the $348.1 million increase in development costs related to oil and natural gas properties during the nine months ended September 30, 2017 over the nine months ended September 30, 2016. Please refer to Note 5—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 financing activities. Net cash provided by financing activities was $2,498.1 million and $1,324.2 million for the nine months ended September 30, 2017 and 2016, respectively. Net cash from financing activities increased by $1,173.9 million in the period ending September 30, 2017, as a result of debt and equity related activity. During the nine months ended September 30, 2017 we received net proceeds from equity offerings of $2,123.3 million and net proceeds from debt offerings of $443.5 million, which was offset by payments on long-term debt of $68.4 million. During the nine months ended September 30, 2016, we received net proceeds from equity offerings of $930.3 million and net proceeds from debt offerings of $395.0 million, which was offset by payments on long-term debt of $0.8 million.

Capital Sources

Revolving Credit Agreement. See Note 7—Debt and Note 15—Subsequent Events to our condensed consolidated financial statements included elsewhere in this Quarterly Report for information regarding the Revolving Credit Agreement.

6.250% Senior Unsecured Notes due 2024. See Note 7—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 7—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 7—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 15—Subsequent Events to our condensed consolidated financial statements included elsewhere in this Quarterly Report for information regarding our 2027 Notes.

Derivative activity. We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we intend to continue our historical practice of entering into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering a portion of our projected oil and natural gas production.

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Working Capital

Our working capital totaled ($39.4) million and ($45.5) million at September 30, 2017 and December 31, 2016, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $242.5 million and $133.4 million at September 30, 2017 and December 31, 2016, respectively. The $109.1 million increase in cash is primarily attributable to the increased debt and equity related activity and offset by acquisitions described in Note 5—Acquisitions and Divestitures to our condensed consolidated financial statements included elsewhere in this Quarterly Report. 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.

Critical Accounting Policies and Estimates

There have not been any material changes during the nine months ended September 30, 2017 to the methodology applied by management for critical accounting policies previously disclosed in our 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 our Annual Report for further description of the Company’s critical accounting policies.

Off-Balance Sheet Arrangements

As of September 30, 2017, we had no material off-balance sheet arrangements.

Contractual Obligations

We had no material changes in our contractual commitments and obligations from amounts listed under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Requirements and Sources of Liquidity-Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2016, except as discussed below.

Firm Transportation and Processing Agreements. During the three months ended September 30, 2017, we entered into a contract that provides firm transportation and processing on one of the pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties, and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. Our condensed consolidated statements of operations reflect our share of these firm transportation and processing costs. This contract requires us to pay a deficiency fee if we fail to deliver the required volumes.

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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 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.

To reduce the impact of price fluctuations on our production revenues, we periodically enter into commodity derivative contracts with respect to portions of our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure to oil price fluctuations. For a description of our open positions at September 30, 2017, see Note 3—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 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 September 30, 2017, the fair market value of our oil and natural gas derivative contracts was a net asset of $15.4 million, including deferred premium payables of $72.5 million. As of September 30, 2017, the fair market value of our oil derivative contracts was a net asset of $14.6 million. Based on our open oil derivative positions at September 30, 2017, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $42.7 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $59.6 million. As of September 30, 2017, the fair market value of our natural gas derivative contracts was a net asset of $0.8 million. Based on our open natural gas derivative positions at September 30, 2017, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately $0.7 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas asset by approximately $0.7 million. Please read “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—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 the 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, who have investment grade ratings.

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Interest Rate Risk

Our market risk exposure related to changes in interest rates relates primarily to debt obligations. We are exposed to changes in interest rates as a result of our Revolving Credit Agreement, and the terms of our Revolving Credit Agreement require us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. An increase in interest rates, however, will not result in increased interest expense until such time that we determine to make borrowings under our Revolving Credit Agreement and, as of September 30, 2017, we had no outstanding borrowings related to our Credit Agreement.

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Item 4. Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, 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) under the Exchange Act) as of September 30, 2017. 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 September 30, 2017, 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 Rule 13a-15(f) under the Exchange Act) during the three months ended September 30, 2017, 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 party to ongoing legal proceedings in the ordinary course of business. 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 our Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our businesses, 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 adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our Annual Report or our other SEC filings other than as set forth below:

We may be unable to successfully integrate Double Eagle’s operations or to realize anticipated cost savings, revenues or other benefits of the Double Eagle Acquisition.

Our ability to achieve the anticipated benefits of the Double Eagle Acquisition will depend in part upon whether we can integrate Double Eagle’s assets and operations into our existing business in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties, including those acquired from Double Eagle, requires an assessment of several factors, including:


•	recoverable reserves;


•	future natural gas and oil prices and their appropriate differentials;


•	availability and cost of transportation of production to markets;


•	availability and cost of drilling equipment and of skilled personnel;


•	development and operating costs and potential environmental and other liabilities; and


•	regulatory, permitting and similar matters.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we have performed, and will continue to perform, a review of the subject properties, including properties that are subject to certain customary acreage swaps in process, that we believe to be generally consistent with industry practices. Our review may not reveal all existing or potential problems or permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even if problems are identified, the contractual protection provided with respect to all or a portion of the underlying deficiencies may prove ineffective or insufficient. The integration process may be subject to delays or changed circumstances, and we can give no assurance that the acquired properties will perform in accordance with our expectations or that our expectations with respect to integration or cost savings as a result of the Double Eagle Acquisition will materialize. Integrating significant acquisitions, including the Double Eagle Acquisition, and other strategic transactions may involve other risks that may cause our business to suffer, including:


•	diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;


•	the challenge and cost of integrating acquired assets and operations with those of ours while carrying on our ongoing business; and

the failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

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

The following sets forth information with respect to our repurchases of shares of Class A Common Stock during the three months ended September 30, 2017:



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
July 2017	5,664	$	28.80	—	$	—
August 2017	—	$	—	—	$	—
September 2017	—	$	—	—	$	—
Total	5,664	$	28.80	—	$	—



(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 accompanying this Quarterly Report.

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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.

November 8, 2017	By:	/s/ Bryan Sheffield
		Bryan Sheffield
		Chairman and Chief Executive Officer (Principal Executive Officer)


November 8, 2017	By:	/s/ Ryan Dalton
		Ryan Dalton
		Executive Vice President—Chief Financial Officer (Principal Accounting and Financial Officer)

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 November 2, 2016).
3.3		First Amendment to the 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 June 5, 2017).
4.1		Indenture, dated May 27, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 6.250% Senior Notes due 2024 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on May 27, 2016).
4.2		First Supplemental Indenture, dated August 18, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 6.250% Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on August 19, 2016).
4.3		Second Supplemental Indenture, dated October 27, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 6.250% Senior Notes due 2024 (incorporated by reference to Exhibit 4.5 to the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
4.4		Third Supplemental Indenture, dated April 20, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 6.250% Senior Notes due 2024 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
4.5		Indenture, dated December 13, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 5.375% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on December 13, 2016).
4.6		First Supplemental Indenture, dated April 20, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 5.375% Senior Notes due 2025 (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
4.7		Indenture, dated February 13, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 5.250% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on February 13, 2017).
4.8		First Supplemental Indenture, dated April 20, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 5.250% Senior Notes due 2025 (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
4.9		Indenture, dated October 11, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, related to the 5.625% Senior Notes due 2027 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on October 11, 2017).
4.10		Registration Rights and Lock-Up Agreement, dated as of April 20, 2017, by and between Parsley Energy, Inc. and the Holders party thereto (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
4.11		Second Amended and Restated Registration Rights Agreement, dated as of April 20, 2017, by and among Parsley Energy, LLC, Parsley Energy, Inc. and each of the parties listed as Owners on the signature pages thereto (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
10.1		Fifth Amendment to Credit Agreement, dated as of October 11, 2017, 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 10.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on October 11, 2017).



10.2		Purchase Agreement, dated October 5, 2017, by and Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers named therein (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 October 11, 2017).
10.3†		Indemnification Agreement, dated as of August 1, 2017, by and between Parsley Energy, Inc. and Karen Hughes (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 August 3, 2017).
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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