Pioneer PE Holding LLC - FORM 10-Q

Pioneer PE Holding LLC - FORM 10-Q - November 2, 2018

Attached files

Attached files

Pioneer PE Holding LLC Reports

file	filename
EX-32.2 - EXHIBIT 32.2 - Pioneer PE Holding LLC	ex-32210xq20180930.htm
EX-32.1 - EXHIBIT 32.1 - Pioneer PE Holding LLC	ex-32110xq20180930.htm
EX-31.2 - EXHIBIT 31.2 - Pioneer PE Holding LLC	ex-31210xq20180930.htm
EX-31.1 - EXHIBIT 31.1 - Pioneer PE Holding LLC	ex-31110xq20180930.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, 2018



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 every Interactive Data File required to be submitted 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 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 2, 2018, the registrant had 280,229,544 shares of Class A common stock and 36,547,731 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	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	53

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 6.	Exhibits	55
	Signatures	57

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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, 2017 (the “Annual Report”) and the risk factors and other cautionary statements contained in our other filings with the United States Securities and Exchange Commission (“SEC”). These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:


•	business strategy;


•	reserves;


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


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


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


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


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


•	hedging strategy and results;


•	future drilling plans;


•	competition and government regulations;


•	ability to obtain permits and governmental approvals;


•	pending legal or environmental matters;


•	marketing of oil, natural gas and NGLs;


•	leasehold, minerals or business acquisitions;


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



(10)	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.



(11)	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 defense, and the maintenance of land and lease records.



	(iii)	Dry hole contributions and bottom hole contributions.



	(iv)	Costs of drilling and equipping exploratory wells.



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



(12)	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.



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



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

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



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



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



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



(19)	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.



(20)	LIBOR. London Interbank Offered Rate.



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



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



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



(24)	MMBtu. One million British thermal units.



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



(26)	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.



(27)	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.



(28)	NYMEX. The New York Mercantile Exchange.



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



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



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



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



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



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



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

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



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



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



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



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



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



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



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



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



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



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



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



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



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



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

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PART 1: FINANCIAL INFORMATION

Item 1: Financial Statements

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2018			December 31, 2017
	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	167,820		$	554,189
Short-term investments	—			149,283
Accounts receivable:
Joint interest owners and other	30,583			42,174
Oil, natural gas and NGLs	179,827			123,147
Related parties	148			388
Short-term derivative instruments, net	30,394			41,957
Assets held for sale	—			1,790
Other current assets	11,062			6,558
Total current assets	419,834			919,486
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method	9,893,801			8,551,314
Accumulated depreciation, depletion and impairment	(1,222,868		)	(822,459		)
Total oil and natural gas properties, net	8,670,933			7,728,855
Other property, plant and equipment, net	145,130			106,587
Total property, plant and equipment, net	8,816,063			7,835,442
NONCURRENT ASSETS
Assets held for sale, net	—			14,985
Long-term derivative instruments, net	13,770			15,732
Other noncurrent assets	7,244			7,553
Total noncurrent assets	21,014			38,270
TOTAL ASSETS	$	9,256,911		$	8,793,198

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses	$	380,251		$	407,698
Revenue and severance taxes payable	135,684			109,917
Current portion of long-term debt	2,373			2,352
Short-term derivative instruments, net	74,337			84,919
Current portion of asset retirement obligations	8,484			7,203
Total current liabilities	601,129			612,089
NONCURRENT LIABILITIES
Liabilities related to assets held for sale	—			405
Long-term debt	2,181,054			2,179,525
Asset retirement obligations	20,429			19,967
Deferred tax liability	130,566			21,403
Payable pursuant to tax receivable agreement	65,039			58,479
Long-term derivative instruments, net	19,862			20,624
Total noncurrent liabilities	2,416,950			2,300,403
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, 280,546,336 shares issued and 279,955,944 shares outstanding at September 30, 2018 and 252,419,601 shares issued and 252,260,300 shares outstanding at December 31, 2017	2,805			2,524
Class B, $0.01 par value, 125,000,000 shares authorized, 36,821,331 and 62,128,257 shares issued and outstanding at September 30, 2018 and December 31, 2017	368			622
Additional paid in capital	5,140,120			4,666,365
Retained earnings	358,873			43,519
Treasury stock, at cost, 590,392 shares and 159,301 shares at September 30, 2018 and December 31, 2017	(11,676		)	(735		)
Total stockholders' equity	5,490,490			4,712,295
Noncontrolling interest	748,342			1,168,411
Total equity	6,238,832			5,880,706
TOTAL LIABILITIES AND EQUITY	$	9,256,911		$	8,793,198

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,
	2018			2017			2018			2017
	(In thousands, except per share data)
REVENUES
Oil sales	$	424,549		$	198,865		$	1,151,977		$	546,676
Natural gas sales	12,810			15,601			42,469			41,051
Natural gas liquids sales	71,294			26,547			169,189			64,296
Other	2,369			8			7,916			3,533
Total revenues	511,022			241,021			1,371,551			655,556
OPERATING EXPENSES
Lease operating expenses	39,777			29,525			104,513			76,783
Transportation and processing costs	8,495			—			21,233			—
Production and ad valorem taxes	30,604			14,808			82,121			37,367
Depreciation, depletion and amortization	157,352			94,819			424,103			247,104
General and administrative expenses (including stock-based compensation of $4,686 and $5,170 for the three months ended September 30, 2018 and 2017 and $15,118 and $14,630 for the nine months ended September 30, 2018 and 2017)	37,555			33,573			108,541			89,376
Exploration and abandonment costs	11,140			88			19,917			4,223
Acquisition costs	—			2,449			2			10,969
Accretion of asset retirement obligations	361			268			1,074			597
Other operating expenses	6,129			2,419			10,781			8,275
Total operating expenses	291,413			177,949			772,285			474,694
OPERATING INCOME	219,609			63,072			599,266			180,862
OTHER INCOME (EXPENSE)
Interest expense, net	(32,854		)	(22,879		)	(98,580		)	(64,979		)
Gain on sale of property	1,383			—			6,438			—
Loss on early extinguishment of debt	—			—			—			(3,891		)
(Loss) gain on derivatives	(22,514		)	(61,955		)	(42,773		)	6,175
Change in TRA liability	—			—			(82		)	(20,549		)
Interest income	1,055			1,013			4,864			5,562
Other (expense) income	(76		)	508			459			1,281
Total other expense, net	(53,006		)	(83,313		)	(129,674		)	(76,401		)
INCOME (LOSS) BEFORE INCOME TAXES	166,603			(20,241		)	469,592			104,461
INCOME TAX (EXPENSE) BENEFIT	(32,454		)	5,080			(89,022		)	(25,538		)
NET INCOME (LOSS)	134,149			(15,161		)	380,570			78,923
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(20,840		)	1,828			(65,216		)	(22,068		)
NET INCOME (LOSS) ATTRIBUTABLE TO PARSLEY ENERGY, INC. STOCKHOLDERS	$	113,309		$	(13,333	)	$	315,354		$	56,855

Net income (loss) per common share:
Basic	$	0.41		$	(0.05	)	$	1.17		$	0.24
Diluted	$	0.41		$	(0.05	)	$	1.16		$	0.24
Weighted average common shares outstanding:
Basic	277,705			246,518			270,262			237,725
Diluted	278,396			246,518			270,846			238,785

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)



	Issued Shares													Shares
	Class A Common Stock	Class B Common Stock		Class A Common Stock		Class B Common Stock			Additional paid in capital			Retained earnings		Treasury stock	Treasury stock			Total stockholders’ equity			Noncontrolling interest			Total equity
	(In thousands)
Balance at December 31, 2017	252,420	62,128		$	2,524	$	622		$	4,666,365		$	43,519	159	$	(735	)	$	4,712,295		$	1,168,411		$	5,880,706
Exchange of PE Units and Class B Common Stock for Class A Common Stock	25,307	(25,307	)	254		(254		)	485,285			—		—	—			485,285			(485,285		)	—
Change in net deferred tax liability due to exchange of PE Units	—	—		—		—			(26,621		)	—		—	—			(26,621		)	—			(26,621		)
Issuance of restricted stock	802	—		8		—			(8		)	—		—	—			—			—			—
Vesting of restricted stock units	919	—		8		—			(8		)	—		—	—			—			—			—
Repurchase of common stock	—	—		—		—			—			—		431	(10,941		)	(10,941		)	—			(10,941		)
Restricted stock forfeited	—	—		—		—			(258		)	—		—	—			(258		)	—			(258		)
Stock-based compensation	—	—		—		—			15,376			—		—	—			15,376			—			15,376
Conversion of restricted stock units to restricted stock awards	1,098	—		11		—			(11		)	—		—	—			—			—			—
Net income	—	—		—		—			—			315,354		—	—			315,354			65,216			380,570
Balance at September 30, 2018	280,546	36,821		$	2,805	$	368		$	5,140,120		$	358,873	590	$	(11,676	)	$	5,490,490		$	748,342		$	6,238,832

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,
	2018			2017
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	380,570		$	78,923
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	424,103			247,104
Accretion of asset retirement obligations	1,074			597
Gain on sale of property	(6,438		)	—
Loss on early extinguishment of debt	—			3,891
Amortization of deferred loan origination costs	3,560			2,826
Amortization of bond premium	(387		)	(387		)
Stock-based compensation	15,118			14,630
Deferred income tax expense	89,022			25,538
Change in TRA liability	82			20,549
Loss (gain) on derivatives	42,773			(6,175		)
Net cash received for derivative settlements	94			13,845
Net cash paid for option premiums	(40,087		)	(19,905		)
Other	18,521			366
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable	(45,089		)	(54,793		)
Accounts receivable—related parties	240			83
Other current assets	(696		)	45,139
Other noncurrent assets	(386		)	(739		)
Accounts payable and accrued expenses	(7,964		)	94,442
Revenue and severance taxes payable	25,767			26,487
Net cash provided by operating activities	899,877			492,421
CASH FLOWS FROM INVESTING ACTIVITIES:
Development of oil and natural gas properties	(1,364,755		)	(733,179		)
Acquisitions of oil and natural gas properties	(96,702		)	(2,131,361		)
Additions to other property and equipment	(62,542		)	(31,947		)
Proceeds from sales of property, plant and equipment	87,954			13,366
Maturity of short-term investments	149,331			—
Other	13,657			2,893
Net cash used in investing activities	(1,273,057		)	(2,880,228		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under long-term debt	—			452,780
Payments on long-term debt	(2,203		)	(68,410		)
Debt issuance costs	(45		)	(9,281		)
Proceeds from issuance of common stock, net	—			2,123,344
Repurchase of common stock	(10,941		)	(300		)
Net cash (used in) provided by financing activities	(13,189		)	2,498,133
Net (decrease) increase in cash, cash equivalents and restricted cash	(386,369		)	110,326
Cash, cash equivalents and restricted cash at beginning of period	554,189			136,669
Cash, cash equivalents and restricted cash at end of period	$	167,820		$	246,995
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	94,392		$	49,565
Cash paid for income taxes	$	—		$	350
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate	$	1,665		$	8,144
(Reductions) additions to oil and natural gas properties - change in capital accruals	$	(19,244	)	$	57,014
Additions to other property and equipment funded by capital lease borrowings	$	1,579		$	3,571
Common stock issued for oil and natural gas properties	$	—		$	1,183,501
Net premiums on options that settled during the period	$	(52,451	)	$	(22,404	)

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1. ORGANIZATION AND NATURE OF OPERATIONS

Parsley Energy, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company”) was formed in December 2013 to succeed 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, natural gas and NGLs reserves located in the Permian Basin, which 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.

NOTE 2. SUMMARY OF ACCOUNTING POLICIES

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

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

The interim data includes all adjustments, consisting only of normal recurring adjustments, 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, 2018 are not necessarily indicative of the operating results of the entire fiscal year ending December 31, 2018.

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


•	impairment of 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.

Reclassifications

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

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In 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 (“ASC 605”), and most industry-specific guidance. The Company adopted this standard effective January 1, 2018 using the modified retrospective approach. As a result, the Company changed its accounting policy for revenue recognition, as discussed in Note 3—Revenue from Contracts with Customers. The Company also implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the required disclosures under the standards.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall, as an amendment to ASC Subtopic 825-10. The amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Among other items, this update will simplify the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment. When a qualitative assessment indicates that impairment exists, an entity is required to measure the investment at fair value. This impairment assessment reduces the complexity of the other-than-temporary impairment guidance that certain entities follow. The Company adopted ASU 2016-01 as of January 1, 2018. The adoption of this guidance did not have a material effect on the Company's financial position, results of operation or cash flows.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), which requires that a statement of cash flows 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 or 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 implemented the new guidance on January 1, 2018 and disclosure revisions have been made for the periods presented on the condensed consolidated statements of cash flows. The Company’s condensed consolidated statements of cash flows for the nine months ended September 30, 2017 were adjusted to conform to this guidance, which resulted in an increase in cash flows from operating activities of $1.2 million.

In March 2018, the FASB issued ASU 2018-05, Income Taxes (Topic 740), which amends certain guidance in ASC 740, Income Taxes, to reflect Staff Accounting Bulletin No. 118, which provides guidance for companies that are not able to complete their accounting for the income tax effects of the Tax Cuts and Jobs Act (the “Tax Act”) during the period of enactment. This guidance also includes amendments to the XBRL Taxonomy. For public business entities, the amendments in ASU 2018-05 are effective for fiscal years ending after December 15, 2020. Early adoption is permitted. The Company has prepared its condensed consolidated financial statements for the three and nine months ended September 30, 2018 in accordance with ASU 2018-05. The Company expects to have all estimates finalized by fourth quarter of 2018. Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax expense. The ultimate impact of the Tax Act may differ from the Company’s estimates based on the Company’s further analysis of the Tax Act and additional regulatory guidance that may be issued in connection therewith.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Recently Issued but Not Yet Adopted Accounting Pronouncements

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 guidance (“ASU 2018-02”). In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842, which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. In July 2018, the FASB issued ASU No. 2018-10, Codification Improvements to Topic 842, Leases, which further clarifies the previously issued guidance. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2018. Early adoption is permitted. In addition, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, which provides an additional transition method that allows entities to apply the new leases standard at the adoption date and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. The Company is in the process of reviewing and determining the contracts for which ASU 2016-02 applies. These contracts include, among others, non-cancelable leases, drilling rig contracts, real estate leases, transportation and gas processing agreements, office equipment leases and contracts for the use of vehicles and well equipment. The Company continues to review current accounting policies, controls, processes, and disclosures that will change as a result of adopting the new standard. Based upon its initial assessment, the Company expects the adoption of ASU 2016-02 will result in an increase in assets and liabilities due to the required recognition of right-of-use (“ROU”) assets and corresponding lease liabilities as well as additional disclosures; however, the full impact to the Company’s consolidated financial statements and related disclosures is still being evaluated. Currently, the Company plans to make certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements, and not to recognize ROU assets or lease liabilities for short-term leases. The Company plans to adopt the guidance on the effective date of January 1, 2019. As permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements.

NOTE 3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Impact of ASC Topic 606 Adoption

The Company’s adoption of ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”), resulted in the following adjustments for the three months ended September 30, 2018 (in thousands):



	Three Months Ended September 30, 2018
	ASC 605		Adjustment		ASC 606
Revenues
Oil sales	$	424,549	$	—	$	424,549
Natural gas sales ⁽¹⁾	11,509		1,301		12,810
Natural gas liquids sales ⁽¹⁾	64,100		7,194		71,294
Total production revenues	500,158		8,495		508,653
Operating expenses
Transportation and processing costs	—		8,495		8,495
Production revenues less transportation and processing costs	$	500,158	$	—	$	500,158

Net income attributable to Parsley Energy, Inc. stockholders	$	113,309	$	—	$	113,309

(1) Revenues associated with natural gas and NGLs sales at the plant inlet are considered a single combined performance obligation. The applicable line items include $3.4 million and $19.7 million of natural gas and NGLs sales, respectively, completed at the plant inlet.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company’s adoption of ASC 606 resulted in the following adjustments for the nine months ended September 30, 2018 (in thousands):



	Nine Months Ended September 30, 2018
	ASC 605		Adjustment		ASC 606
Revenues
Oil sales	$	1,151,977	$	—	$	1,151,977
Natural gas sales ⁽¹⁾	38,189		4,280		42,469
Natural gas liquids sales ⁽¹⁾	152,236		16,953		169,189
Total production revenues	1,342,402		21,233		1,363,635
Operating expenses
Transportation and processing costs	—		21,233		21,233
Production revenues less transportation and processing costs	$	1,342,402	$	—	$	1,342,402

Net income attributable to Parsley Energy, Inc. stockholders	$	315,354	$	—	$	315,354

(1) Revenues associated with natural gas and NGLs sales at the plant inlet are considered a single combined performance obligation. The applicable line items include $12.0 million and $46.5 million of natural gas and NGLs sales, respectively, completed at the plant inlet.

Changes to natural gas and NGLs sales were made in accordance with the new control model defined in ASC 606. Under the new control model, the Company was required to identify and separately analyze each contract associated with revenues to determine the appropriate accounting application. The Company considered various indicators for contracts and the weighting of their relevance to determine when control transferred to the customer (such as whether raw gas is sold at the receipt point or residue gas and NGLs are sold at the tailgate of the gas processing plants). Based on this analysis, the Company concluded that the presence of product redelivery and take-in-kind rights, if substantive, are determinative indicators of control transferring at the tailgate if there is intent at contract inception. Additionally, the Company considers risk of loss an important indicator of when control transfers, which is comprised of risks associated with loss of product, exposure to product mix and recoveries, and exposure to index prices versus actual prices. The Company concluded that title, custody, and acceptance are not determinative indicators of control, as such factors may be present in the case of a sale or the performance of a service.

As a result of this analysis, the Company modified its accounting and presentation of natural gas and NGLs sales, and transportation and processing costs under certain marketing agreements. This is due to the conclusion that the Company represents the principal and the ultimate third party is its customer, which implies that the Company maintains control of the product through the tailgate of gas processing plants in certain natural gas processing and marketing agreements with certain midstream entities in accordance with the control model in ASC 606. This is a change from previous conclusions reached by the Company for these agreements, when utilizing the principal versus agent indicators under ASC 605, where the Company acted as the agent and the midstream processing entity acted as its customer. As a result, the Company modified its presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Transportation and processing costs related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as Transportation and processing costs on the Company’s condensed consolidated statements of operations.

Certain of the Company’s contracts for the sale of commodities contain embedded derivatives. The Company has elected to utilize the normal purchases and normal sales scope exception as provided by ASC Topic 815, Derivatives and Hedging.

Revenue from Contracts with Customers

Revenue is measured based on considerations specified in contracts with customers, excluding any sales incentives or amounts collected on behalf of third parties. The Company recognizes revenue when a performance obligation is satisfied by the transfer of control over a product to the ultimate customer. Sales of oil, natural gas and NGLs are recognized at the time that control of the product is transferred to the customer and collectability is reasonably assured. Generally, the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

delivers to a gathering or transmission line, the quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the prices of the Company’s oil, natural gas, and NGLs fluctuate to remain competitive with other available oil, natural gas, and NGLs supplies. The Company reports revenues disaggregated by product on its condensed consolidated statements of operations.

Oil Sales

Oil production is sold at the wellhead and the Company collects an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received by the Company.

Natural Gas and NGLs Sales

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

Production Imbalances

Previously, the Company elected to utilize the entitlements method, which is no longer applicable, to account for natural gas production imbalances. The Company now utilizes the sales method to account for natural gas production imbalances; if the Company sells natural gas to a customer in excess of its entitled share of production, the Company is required perform a principal versus agent analysis to determine whether it should record the gross amount of revenue and transportation and processing costs equal to the other owners’ interests or recognize the net amount of revenue. In conjunction with the adoption of ASC 606, for the three and nine months ended September 30, 2018, there was no material impact to the financial statements due to this change in accounting for production imbalances.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature, with a contract term of one year or less. For these contracts, the Company has utilized the practical expedient in ASC 606-10-50-14, which exempts the Company from the requirements to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. Settlement statements for certain natural gas and NGLs sales, however, may not be received for 30 to 90 days after the date production is delivered, and as a result the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. In these situations, the Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between the Company’s revenue estimates and actual revenue received have historically been insignificant. For the three and nine months ended September 30, 2018 and 2017, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Instruments and Concentration of Risk

Objective and Strategy

The Company enters into multiple types of commodity derivative contracts to (i) reduce the effect of price volatility on the Company’s oil and natural gas revenues and (ii) support the Company’s annual capital budgeting and expenditure plans.

Oil Production Derivative Activities

The Company’s material physical sales contracts governing its oil production are typically correlated with NYMEX WTI, including Cushing (“WTI Cushing”), Midland (“WTI Midland”) and Magellan East Houston (“WTI MEH”) oil prices. The Company uses put spread options, three-way collars and two-way collars to manage oil price volatility. The Company uses basis swap contracts to reduce basis risk between NYMEX WTI prices and the actual index prices at which the oil is sold. The Company uses rollfactor swap contracts to reduce the timing risk associated with physical sales; the rollfactor swap contracts fix the adjustment at the swap price to ensure that the Company receives a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

As of September 30, 2018, the Company had the following outstanding oil derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.



Put spreads⁽¹⁾	Three Months Ending December 31, 2018			Year Ending December 31, 2019
	WTI Cushing			WTI Cushing			WTI Midland		WTI MEH
Volume (MBbls)		3,450		8,100			2,400		1,500
Long put price (per Bbl)		$	49.67	$	56.76		$	50.63	$	64.00
Short put price (per Bbl)		$	39.67	$	46.76		$	40.63	$	54.00

Three-way collars		Three Months Ending December 31, 2018					Year Ending December 31, 2019
		WTI Cushing					WTI Cushing
Volume (MBbls)				2,850					3,300
Short call price (per Bbl)				$	75.65				$	80.36
Long put price (per Bbl)				$	50.00				$	50.45
Short put price (per Bbl)				$	40.00				$	40.45

Two-way collars							Three Months Ending December 31, 2018
							WTI Cushing
Volume (MBbls)									276
Short call price (per Bbl)									$	61.31
Long put price (per Bbl)									$	45.67

		Three Months Ending December 31, 2018					Year Ending December 31, 2019
		Volume (MBbls)		Fixed Price Swap (per Bbl)			Volume (MBbls)		Fixed Price Swap (per Bbl)
Basis swap - Midland-Cushing index⁽²⁾		1,702		$	(3.76	)	2,760		$	(8.57	)
Basis swap - Houston-Cushing index⁽²⁾		—		—			780		$	5.10
Rollfactor swap - Midland-Cushing index⁽³⁾		1,380		$	0.60		—		$	—



(1)	Excludes 2,444 notional MBbls with a fair value of $9.0 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.
(3)	These positions hedge the timing risk associated with the Company’s physical sales. The Company generally sells crude oil for the delivery month at a sales price based on the average NYMEX price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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



Three-way collars	Three Months Ending December 31, 2018
	NYMEX Henry Hub
Volume (MMbtu)	750,000
Short put price (per MMbtu)	$	2.75
Long put price (per MMbtu)	$	3.00
Short call price (per MMbtu)	$	3.60

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, 2018 and 2017 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Changes in fair value of derivative instruments	$	(31,890	)	(72,937		)	$	(42,257	)	(9,479		)
Net derivative settlements	9,376			10,982			(516		)	15,654
(Loss) gain on derivatives	$	(22,514	)	$	(61,955	)	$	(42,773	)	$	6,175

Net premiums on options that settled during the period ⁽¹⁾	$	(17,853	)	$	(12,487	)	$	(52,451	)	$	(22,404	)



(1)	The net premium on options that settled during the period represents the cumulative cost of premiums paid and received on positions purchased and sold, which expired during the current period.

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 15—Disclosures about Fair Value of Financial Instruments. The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and liabilities at settlement or in the event of default under the agreements. Additionally, the Company maintains accounts with its brokers to facilitate financial derivative transactions in support of its risk management activities. Based on the value of the Company’s positions in these accounts and the associated margin requirements, the Company may be required to deposit cash into these broker accounts. During the three and nine months ended September 30, 2018 and 2017, the Company did not receive or post any material margins in connection with collateralizing its derivative positions.

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(Unaudited)

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



	Gross Amount			Netting Adjustments			Net Exposure
September 30, 2018
Derivative assets with right of offset or master netting agreements	$	53,168		$	(9,004	)	$	44,164
Derivative liabilities with right of offset or master netting agreements	(103,203		)	9,004			(94,199		)

December 31, 2017
Derivative assets with right of offset or master netting agreements	$	59,132		$	(1,443	)	$	57,689
Derivative liabilities with right of offset or master netting agreements	(106,986		)	1,443			(105,543		)

Concentration of Credit Risk

The Company believes that it has limited credit risk with respect to its exchange-traded contracts, as such contracts are subject to financial safeguards and transaction guarantees through NYMEX. Over-the-counter traded options expose the Company to counterparty credit risk. These over-the-counter options are entered into with large multinational financial institutions with investment grade credit ratings or through brokers that require all the transaction parties to collateralize their open option positions. The gross and net credit exposure from the Company’s commodity derivative contracts as of September 30, 2018 and December 31, 2017 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. If the Company believes a counterparty’s creditworthiness has declined or is suspect, it may seek to novate the applicable ISDA Agreement to another financial institution that has an ISDA Agreement in place with the Company. The Company did not incur any losses due to counterparty nonperformance during the three and nine months ended September 30, 2018 or the year ended December 31, 2017.

Credit Risk Related Contingent Features in Derivatives

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

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(Unaudited)

NOTE 5. PROPERTY, PLANT AND EQUIPMENT

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



	September 30, 2018			December 31, 2017
Oil and natural gas properties:
Subject to depletion	$	6,169,421		$	4,492,802
Not subject to depletion
Incurred in 2018	570,413			—
Incurred in 2017	2,174,583			2,837,766
Incurred in 2016 and prior	979,384			1,220,746
Total not subject to depletion	3,724,380			4,058,512
Oil and natural gas properties, successful efforts method	9,893,801			8,551,314
Less accumulated depreciation, depletion and impairment	(1,222,868		)	(822,459		)
Total oil and natural gas properties, net	8,670,933			7,728,855
Other property, plant and equipment	177,155			131,115
Less accumulated depreciation	(32,025		)	(24,528		)
Other property, plant and equipment, net	145,130			106,587
Total property, plant and equipment, net	$	8,816,063		$	7,835,442

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

As the Company’s exploration and development work progresses and the reserves on the Company’s properties are proven, capitalized costs attributed to the properties 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 $153.4 million and $412.9 million for the three and nine months ended September 30, 2018, respectively, and $91.7 million and $238.8 million for the three and nine months ended September 30, 2017, respectively. The Company had no exploratory wells in progress at September 30, 2018 or December 31, 2017.

NOTE 6. ACQUISITIONS AND DIVESTITURES

Acquisitions

During the three and nine months ended September 30, 2018, the Company incurred costs of $40.7 million and $96.7 million, respectively, related to the purchase of leasehold acreage. During the three and nine months ended September 30, 2018, the Company reflected $35.5 million and $86.4 million, respectively, as part of costs not subject to depletion and $5.2 million and $10.3 million, respectively, as part of costs subject to depletion within its oil and natural gas properties.

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

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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 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 were subsequently renamed 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 $1,395.6 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 4,921,557 PE Units (and a corresponding 4,921,557 shares of Class B Common Stock) were deposited in an indemnity holdback escrow account. On April 16, 2018, approximately $138.4 million and 3,937,246 PE Units (and a corresponding 3,937,246 shares of Class B Common Stock) were released from the indemnity holdback escrow account.

During the three and nine months ended September 30, 2018 and September 30, 2017, the Company exchanged certain leasehold acreage and oil and natural gas properties with third parties, with no gain or loss recognized.

Divestitures

During the three months and nine months ended September 30, 2018, Pacesetter completed the sale of all of its physical assets for consideration equivalent to $13.1 million, consisting of $11.0 million in cash and a $2.1 million term loan that is due to mature during the fourth quarter of 2018. Following the liquidation of Pacesetter, which is expected to take place in 2019, its remaining assets will be distributed to its members, including Parsley Energy Operations, LLC, a wholly owned subsidiary of Parsley LLC. The Company recognized a $1.2 million gain on the sale.

During the nine months ended September 30, 2018, the Company closed the sale of certain surface and mineral acreage for proceeds of $34.4 million, subject to customary purchase price adjustments. The Company recognized a $5.2 million gain on the sale.

During the nine months ended September 30, 2018, the Company also closed sales of certain leasehold acreage for proceeds of $42.6 million, including customary purchase price adjustments. Upon closing these sales, the Company recognized no gain or loss in accordance with the guidance for partial sales of oil and natural gas properties under ASC Topic 932, Extractive Activities—Oil and Gas.

NOTE 7. 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, 2018 (in thousands):



	September 30, 2018
Asset retirement obligations, beginning of period	$	27,170
Additional liabilities incurred	1,665
Accretion expense	1,074
Liabilities settled upon plugging and abandoning wells	(261		)
Disposition of wells	(735		)
Asset retirement obligations, end of period	$	28,913

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NOTE 8. DEBT

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



	September 30, 2018			December 31, 2017
Revolving Credit Agreement	$	—		$	—
6.250% senior unsecured notes due 2024	400,000			400,000
5.375% senior unsecured notes due 2025	650,000			650,000
5.250% senior unsecured notes due 2025	450,000			450,000
5.625% senior unsecured notes due 2027	700,000			700,000
Capital leases	4,287			4,906
Total debt	2,204,287			2,204,906
Debt issuance costs on senior unsecured notes	(23,786		)	(26,341		)
Premium on senior unsecured notes	2,926			3,312
Less: current portion of debt	(2,373		)	(2,352		)
Total long-term debt	$	2,181,054		$	2,179,525

Revolving Credit Agreement

As of September 30, 2018, the borrowing base under the Revolving Credit Agreement was $2.3 billion, with a commitment level of $1.0 billion. There were no borrowings outstanding and $8.8 million in letters of credit outstanding as of September 30, 2018, resulting in availability of $991.3 million. The amount Parsley LLC is able to borrow under the Revolving Credit Agreement is subject to compliance with the financial covenants, satisfaction of various conditions precedent to borrowing and other provisions of the Revolving Credit Agreement.

As of September 30, 2018, letters of credit under the Revolving Credit Agreement bear a 1.25% weighted average interest rate.

Covenant Compliance

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

As of September 30, 2018, the Company was in compliance with all required covenants under the Revolving Credit Agreement and each of the indentures governing the Notes.

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Principal Maturities of Debt

Principal maturities of debt outstanding at September 30, 2018 are as follows (in thousands):



2018	$	601
2019	2,267
2020	1,108
2021	275
2022	33
Thereafter	2,200,003
Total	$	2,204,287

Interest Expense

The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2018 and 2017 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Cash payments for interest	$	30,345		$	34,463		$	94,392		$	49,565
Change in interest accrual	1,452			(12,478		)	1,015			12,975
Amortization of deferred loan origination costs	1,186			1,023			3,560			2,826
Amortization of bond premium	(129		)	(129		)	(387		)	(387		)
Total interest expense, net	$	32,854		$	22,879		$	98,580		$	64,979

NOTE 9. 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 the Company’s 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, 2018 and 2017, 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, 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 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,
	2018		2017			2018		2017
Basic EPS (in thousands, except per share data)
Numerator:
Basic net income (loss) attributable to Parsley Energy, Inc. Stockholders	$	113,309	$	(13,333	)	$	315,354	$	56,855
Denominator:
Basic weighted average shares outstanding	277,705		246,518			270,262		237,725
Basic EPS attributable to Parsley Energy, Inc. Stockholders	$	0.41	$	(0.05	)	$	1.17	$	0.24
Diluted EPS
Numerator:
Net income (loss) attributable to Parsley Energy, Inc. Stockholders	113,309		(13,333		)	315,354		56,855
Diluted net income (loss) attributable to Parsley Energy, Inc. Stockholders	$	113,309	$	(13,333	)	$	315,354	$	56,855
Denominator:
Basic weighted average shares outstanding	277,705		246,518			270,262		237,725
Effect of dilutive securities:
Time-Based Restricted Stock and Time-Based Restricted Stock Units	691		—			584		1,060
Diluted weighted average shares outstanding ⁽¹⁾	278,396		246,518			270,846		238,785
Diluted EPS attributable to Parsley Energy, Inc. Stockholders	$	0.41	$	(0.05	)	$	1.16	$	0.24

(1)

As of September 30, 2018 and 2017, there were 1,356,522 shares of performance-based restricted stock (“PSAs”) and 640,062 performance-based restricted stock units (“PSUs”), respectively, that could vest 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, 2018 and 2017, 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 equity offerings completed by the Company in 2017, the consummation of the Double Eagle Acquisition and exchanges by holders of PE Units (the “PE Unit Holders”) during 2017, the Company’s ownership of Parsley LLC decreased from 86.5% to 80.2% and the PE Unit Holders’ ownership of Parsley LLC increased from 13.5% to 19.8%.

During the nine months ended September 30, 2018, 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 25,306,926 PE Units (and a corresponding number of shares of Class B Common Stock) for an aggregate of 25,306,926 shares of the Company’s Class A common stock, par value $0.01 per share (“Class A Common Stock”). In turn, the Company exercised its call right under the Parsley LLC Agreement, electing to issue Class A Common Stock directly to each of the exchanging PE Unit Holders in satisfaction of their 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 nine months ended September 30, 2018, the Company’s ownership in Parsley LLC increased from 80.2% to 88.4% and the ownership of the PE Unit Holders in Parsley LLC decreased from 19.8% to 11.6%.

Because these changes in the Company’s ownership interest in Parsley LLC did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, Consolidation, which requires that any differences between the carrying value of the Company’s basis in Parsley LLC and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest.

The Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the PE Unit Holders as a noncontrolling interest.

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The following table summarizes the noncontrolling interest income (loss):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
	(In thousands)
Net income (loss) attributable to the noncontrolling interests of:
Parsley LLC	$	20,327	$	(1,353	)	$	64,446	$	22,604
Pacesetter Drilling, LLC	513		(475		)	770		(536		)
Total net income (loss) attributable to noncontrolling interest	$	20,840	$	(1,828	)	$	65,216	$	22,068

NOTE 10. STOCK-BASED COMPENSATION

In connection with the Company’s initial public offering (the “IPO”), the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan for employees, consultants, and directors of the Company who perform services for the Company. Refer to “Compensation Discussion and Analysis—Elements of Compensation—Incentive Compensation” in the Company’s Proxy Statement filed on Schedule 14A for the 2018 Annual Meeting of Stockholders for additional information related to this equity based compensation plan.

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

Stock-based compensation expense recorded for each type of stock-based compensation award for the three and nine months ended September 30, 2018 and 2017 is as follows (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Time-based restricted stock	$	1,787	$	1,532	$	5,841	$	4,140
Time-based restricted stock units	1,059		1,947		4,091		5,825
Performance-based restricted stock awards ⁽¹⁾	1,840		1,691		5,186		4,665
Total stock-based compensation	$	4,686	$	5,170	$	15,118	$	14,630


(1)	Includes stock based compensation expense related to historical PSUs.

Stock-based compensation is included in General and administrative expenses in the Company’s condensed consolidated statements of operations included within this Quarterly Report. There was approximately $27.8 million of unamortized compensation expense relating to outstanding RSAs, RSUs, and PSAs at September 30, 2018. 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, performance-based restricted stock unit, and performance-based restricted stock award activity for the nine months ended September 30, 2018 (in thousands):



	Time-Based Restricted Stock (RSAs)			Time-Based Restricted Stock Units (RSUs)			Performance-Based Restricted Stock Units (PSUs)			Performance-Based Restricted Stock Awards (PSAs)
Outstanding at January 1, 2018	779			1,200			640			—
Granted ⁽¹⁾	302			288			—			500
Converted	242			(242		)	(428		)	856
Vested	(593		)	(495		)	(212		)	—
Forfeited	—			(69		)	—			—
Outstanding at September 30, 2018	730			682			—			1,356

(1) Weighted average grant date fair value	$	27.91		$	27.44		$	—		$	13.72

NOTE 11. INCOME TAXES

The Company is a corporation and is subject to U.S. federal income tax and the Texas Margins Tax. On December 22, 2017, Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, was enacted by the U.S. government. The Tax Act significantly impacted the Company’s 2017 effective tax rate and made broad and complex changes to the U.S. corporate income tax code. Among other changes, the Tax Act: (i) reduced the U.S. federal corporate income tax rate from 35% to 21%; (ii) repealed the corporate alternative minimum tax and provides for a refund of previously accrued alternative minimum tax credits; (iii) modified the provisions relating to the limitations on deductions for executive compensation of publicly traded corporations; (iv) enacted new limitations regarding the deductibility of interest expense; and (v) imposed new limitations on the utilization of net operating losses arising in taxable years beginning after December 31, 2017.

GAAP requires that the impact of tax legislation be recognized in the period in which the law was enacted. As a result of the Tax Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, and they now generally reflect a federal income tax rate of 21%. Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax expense. The ultimate impact of the Tax Act may differ from the Company’s estimates based on the Company’s further analysis of the new law and additional regulatory guidance that may be issued. Further, the amount of the Company’s future federal income tax will be dependent upon its future taxable income.

The Company’s effective combined U.S. federal and state income tax rate for the nine months ended September 30, 2018 and 2017 was 19.0% and 24.5%, respectively. During the three and nine months ended September 30, 2018, the Company recognized an income tax expense of $32.5 million and $89.0 million, 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. Total income tax expense for the three and nine months ended September 30, 2018 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% 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 2017.

The net effect of the exchange of PE Units and Class B Common Stock for Class A Common Stock during the nine months ended September 30, 2018 was an increase of deferred tax liability of $20.3 million.

Tax Receivable Agreement

In connection with the IPO, on May 29, 2014, the Company entered into a Tax Receivable Agreement (the “TRA”) with Parsley LLC and certain PE Unit Holders prior to the IPO (each such person, a “TRA Holder”), including certain executive officers. The TRA generally provides for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of (i) any tax basis increases resulting from the contribution in connection with the IPO by

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such TRA Holder of all or a portion of its PE Units to the Company in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange by such TRA Holder of PE Units for shares of Class A Common Stock or, if either the Company or Parsley LLC so elects, cash, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRA. The term of the TRA commenced on May 29, 2014, and continues until all such tax benefits have been utilized or expired, unless the Company exercises its right to terminate the TRA. If the Company elects to terminate the TRA early, it would be required to make an immediate payment equal to the present value of the hypothetical future tax benefits that could be paid under the TRA (based upon certain assumptions and deemed events set forth in the TRA). In addition, payments due under the TRA will be similarly accelerated following certain mergers or other changes of control.

The actual amount and timing of payments to be made under the TRA will depend on a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers and the portion of the Company’s payments under the TRA constituting imputed interest. As of September 30, 2018, there have been no payments associated with the TRA.

As a result of the exchange of PE Units by certain TRA Holders, the Company recorded additional deferred tax assets of $7.6 million during the nine months ended September 30, 2018. The amount payable pursuant to the TRA increased by $6.6 million, which is 85% of the deferred tax asset, and additional paid in capital increased by $1.1 million.

As of September 30, 2018 and December 31, 2017, the Company had recorded a TRA liability of $65.0 million and $58.5 million, respectively, for the estimated payments that will be made to the TRA Holders who have exchanged shares along with corresponding deferred assets, net of valuation allowance, of $76.5 million and $68.8 million, respectively, as a result of the increase in tax basis arising from such exchanges and the decrease in tax basis as a result of the decrease in the future statutory tax rate.

NOTE 12. 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 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 ASC 410 Asset Retirement and Environmental Obligations. 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, 2018 and December 31, 2017, 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, 2017, except as described below.

Firm Transportation and Crude Oil Sales Agreements. During the three months ended September 30, 2018, the Company entered into certain agreements providing for the transportation and/or sale of crude oil. Each of these agreements contains minimum volume commitments, some of which remain subject to the completion of certain pipeline systems. Satisfaction of these volume requirements includes volumes produced by the Company, and other third-party working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf. The Company’s consolidated statements of operations reflects its share of costs related to firm transportation and crude oil sales. Subject to provisions that mitigate the potential impact of volume shortfalls, these agreements require the Company to pay deficiency fees if it fails to deliver the required volumes of crude oil.

NOTE 13. RELATED PARTY TRANSACTIONS

Well Operations

During the three and nine months ended September 30, 2018 and 2017, 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, 2018 totaled $0.5 million and $1.4 million, respectively. 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.

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

Spraberry Production Services, LLC

As discussed in Note 2—Summary of Accounting Policies, the Company owns a 42.5% interest in SPS. The Company accounts for this investment using the equity method. Using the equity method of accounting results in transactions between the Company and SPS and its subsidiaries being accounted for as related party transactions. During the three and nine months ended September 30, 2018, the Company incurred charges totaling $1.7 million and $9.7 million, respectively, as compared to $2.5 million and $8.1 million, respectively, for the three and nine months ended September 30, 2017, 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, 2018, the Company incurred charges totaling $0.1 million and $3.8 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, 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.

Exchange Right

In accordance with the terms of the Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange (the “Exchange Right”) their PE Units (and a corresponding number of shares of the Class B Common Stock) for shares of Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each PE Unit (and a corresponding share of Class B Common Stock) exchanged (subject to conversion rate adjustments for stock splits, stock dividends and reclassifications) or, if the Company or Parsley LLC so elects, cash. As a PE Unit Holder exchanges its PE Units, the Company’s interest in Parsley LLC will be correspondingly increased. Refer to Note 9—Equity—Noncontrolling Interest in the Company’s condensed consolidated financial statements for additional discussion.

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During the three months ended September 30, 2018, an officer of the Company elected to exchange 250,000 PE Units (and a corresponding number of shares of Class B Common Stock) for 250,000 shares of Class A Common Stock. The Company exercised its call right under the Parsley LLC Agreement and elected to issue Class A Common Stock to the exchanging PE Unit Holder in satisfaction of such individual’s election notice.

NOTE 14. SIGNIFICANT CUSTOMERS

For the nine months ended September 30, 2018 and 2017, each of the following purchasers accounted for more than 10% of the Company’s revenue:



	Nine Months Ended September 30,
	2018	2017
Shell Trading (US) Company	53%	65%
Lion Oil, Inc.	21%	—%
Targa Pipeline Mid-Continent, LLC	11%	13%

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

NOTE 15. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS

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



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

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Proved oil and natural gas properties. During the three and nine months ended September 30, 2018 and 2017, the Company did not recognize impairment charges, as the carrying amount of the assets exceeds the undiscounted future cash flows of the assets.

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

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

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, 2018
	Level 1		Level 2			Level 3		Total
Assets:
Money market funds	$	102,687	$	—		$	—	$	102,687
Commodity derivative instruments⁽¹⁾	—		44,164			—		44,164
Total assets	$	102,687	$	44,164		$	—	$	146,851

Liabilities:
Commodity derivative instruments⁽¹⁾	$	—	$	(94,199	)	$	—	$	(94,199	)
Total liabilities	$	—	$	(94,199	)	$	—	$	(94,199	)
Net asset (liability)	$	102,687	$	(50,035	)	$	—	$	52,652



	December 31, 2017
	Level 1		Level 2			Level 3		Total
Assets:
Money market funds	$	476,619	$	—		$	—	$	476,619
Commodity derivative instruments⁽¹⁾	—		57,689			—		57,689
Total assets	$	476,619	$	57,689		$	—	$	534,308

Liabilities:
Commodity derivative instruments⁽¹⁾	$	—	$	(105,543	)	$	—	$	(105,543	)
Total liabilities	$	—	$	(105,543	)	$	—	$	(105,543	)
Net asset (liability)	$	476,619	$	(47,854	)	$	—	$	428,765



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

Money market funds in the preceding tables consist of money market funds included in cash and cash equivalents on the Company’s consolidated balance sheets at September 30, 2018 and December 31, 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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

months ended September 30, 2018, income related to these investments was $0.7 million and $4.2 million, respectively, and is recorded on the Company’s condensed consolidated statements of operations as Interest income. During the three and nine months ended September 30, 2017, income related to these investments was $0.9 million and $5.3 million, respectively, and is recorded on the Company’s condensed consolidated statements of operations as Interest income.

Commodity derivative contracts are marked-to-market each quarter and are thus stated at fair value in the accompanying condensed consolidated balance sheets and in Note 4—Derivative Financial Instruments. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements because they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.

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, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents:
Commercial paper	$	—	$	—	$	24,939	$	24,918
Short-term investments:
Commercial paper	—		—		149,283		149,151
Long-term debt:
6.250% senior unsecured notes due 2024	400,000		418,920		400,000		423,824
5.375% senior unsecured notes due 2025	650,000		653,601		650,000		658,483
5.250% senior unsecured notes due 2025	450,000		450,153		450,000		454,010
5.625% senior unsecured notes due 2027	700,000		706,902		700,000		715,169
Revolving Credit Agreement	—		—		—		—

The fair values of the Notes were determined using the September 30, 2018 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, 2018, there are no indicators for change in the Company’s market spread.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 income.

Effect of Financial Instruments on the Condensed Consolidated Financial Statements

The following tables provide the components of the Company’s cash and cash equivalents and short-term investments as of the dates indicated (in thousands):



	September 30, 2018
Consolidated Balance Sheet Location	Cash		Commercial Paper		Money Market Funds		Total
Cash and cash equivalents	$	65,133	$	—	$	102,687	$	167,820



	December 31, 2017
Consolidated Balance Sheet Location	Cash		Commercial Paper		Money Market Funds		Total
Cash and cash equivalents	$	52,631	$	24,939	$	476,619	$	554,189
Short-term investments	—		149,283		—		149,283

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 16. SUBSEQUENT EVENTS

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

The Company entered into an agreement to divest non-core acreage, for approximately $136.3 million in cash, subject to customary closing conditions and adjustments. The transaction is anticipated to close during the fourth quarter of 2018.

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

The following discussion and analysis should be read in conjunction with the accompanying financial statements and related notes. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed above in “Cautionary Note Regarding Forward-Looking Statements” and in our Annual Report on Form 10-K for the year ended December 31, 2017 (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 to succeed 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 an independent oil and natural gas company focused on the acquisition and development of unconventional oil, natural gas and NGLs 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, given the historical associated returns, we focus predominantly on horizontal development drilling.

As a holding company and the sole managing member of Parsley Energy, LLC (“Parsley LLC”), (i) our sole material asset consists of 279,955,944 PE Units as of September 30, 2018, (ii) we are responsible for all operational, management and administrative decisions of Parsley LLC, and (iii) we consolidate the financial results of Parsley LLC and its subsidiaries.

Our Properties

The following table sets forth information as of September 30, 2018 relating to our leasehold acreage:



	Developed Acreage		Undeveloped Acreage		Total Acreage
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	175,401	125,082	61,024	39,114	236,425	164,196
Delaware Basin	35,522	32,957	14,375	11,966	49,897	44,923
Total	210,923	158,039	75,399	51,080	286,322	209,119

In addition to the leasehold acreage described above, as of September 30, 2018, we held mineral and/or royalty interests in 70,375 gross acres. 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.

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As of September 30, 2018, we operated the following wells:



	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	998	762.5	344	321.5	1,342	1,084.0
Delaware Basin	13	12.5	83	78.5	96	91.0
Total	1,011	775.0	427	400.0	1,438	1,175.0

As of September 30, 2018, we held an interest in 1,879 gross (1,239.5 net) wells, including wells that we do not operate. As of September 30, 2018, 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, 2018, we have placed on production 320 gross (300.3 net) horizontal wells in the Midland Basin and 64 gross (61.5 net) horizontal wells in the Delaware Basin. The table below summarizes the horizontal wells placed on production during the periods indicated:



	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Area	Gross	Net	Gross	Net
Midland Basin	38	37.4	95	92.4
Delaware Basin	8	7.7	37	36.0
Total	46	45.1	132	128.4

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.

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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.

Natural gas and NGLs sales and associated production volumes for the three and nine months ended September 30, 2018 reflect adjustments associated with our adoption of ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”), effective January 1, 2018, as discussed in Factors Affecting the Comparability of our Financial Condition and Results of Operations—Impact of ASC Topic 606 Adoption.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Oil sales	83	%	83	%	85	%	84	%
Natural gas sales	3	%	6	%	3	%	6	%
Natural gas liquids sales	14	%	11	%	12	%	10	%

Other revenues are not material and 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, 2018 and 2017:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Oil (MBbls)	6,763	4,342	18,269	11,653
Natural gas (MMcf)	9,878	6,265	27,669	16,105
Natural gas liquids (MBbls)	2,281	1,194	6,030	3,063
Total (MBoe)	10,690	6,581	28,911	17,402
Average net production (Boe/d)	116,196	71,534	105,901	63,744

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 depends on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through the development of our properties as well as through acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions.

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

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

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, we enter into derivative arrangements for a portion of our production, with an emphasis on our oil production. By removing a 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.

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We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our oil, natural gas or NGLs production. See Note 4—Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this Quarterly Report for details regarding volumes and terms of our derivative instruments as of September 30, 2018.

We will have recognized the following cumulative losses in the line item (Loss) gain 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 2018	(19,114		)
Q1 2019	(11,626		)
Q2 2019	(12,523		)
Q3 2019	(12,049		)
Q4 2019	(12,048		)
Total	$	(67,360	)

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.

Given the volatility of commodity prices in recent years and their impact on our estimated future cash flows, we have continued to review our proved oil and natural gas properties for impairment on a quarterly basis. During the three and nine months ended September 30, 2018 and 2017, we did not recognize an impairment of our proved oil and natural gas properties. At September 30, 2018, in our significant fields that comprise 100% of our carrying value, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and natural gas properties by an average of 168% per field and, individually, by a minimum of 156%.

The key assumptions used to determine the undiscounted future cash flows include, but are not limited to, future commodity prices, price differentials, future production estimates, estimated future capital expenditures and estimated future operating expenses. All inputs in the undiscounted future cash flow estimate, except commodity price estimates, remained relatively consistent from September 30, 2017 to September 30, 2018. We evaluate future commodity pricing for oil and NGLs based on five-year WTI futures prices, which increased from September 30, 2017 to September 30, 2018, and future commodity pricing for natural gas based on five-year Henry Hub futures prices, which decreased from September 30, 2017 to September 30, 2018. In terms of the increase in value of undiscounted cash flows from September 30, 2017 to September 30, 2018, the effect of the increase in oil and NGLs prices 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 respect to the assumptions used to estimate future undiscounted cash flows due to, but not limited to, the risk factors referred to in “Item 1A. Risk Factors” included in the Annual Report.

Any decrease in pricing, negative change in price differentials or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties. A decrease of 10% in estimated future pricing of oil and natural gas commodities as of September 30, 2018, however, would not have resulted in an impairment of our proved oil and natural gas properties.

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

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

Capital Expenditures

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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Capital expenditures	$	444,314	$	306,788	$	1,345,511	$	790,193

Our capital expenditures for drilling, completions and infrastructure (including facility buildout) were $1,207.4 million for the year ended December 31, 2017, of which our aggregate drilling and completion expenditures were $1,049.6 million and our infrastructure and other expenditures were $157.8 million.

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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Impact of ASC Topic 606 Adoption

We adopted ASC 606 effective January 1, 2018 using the modified retrospective approach. As a result, we changed our accounting policy for revenue recognition, which resulted in the following adjustments:



	Three Months Ended September 30, 2018
	ASC 605		Adjustment			ASC 606
Production revenues (in thousands):
Oil sales	$	424,549	$	—		$	424,549
Natural gas sales ⁽¹⁾	11,509		1,301			12,810
Natural gas liquids sales ⁽¹⁾	64,100		7,194			71,294
Total production revenues	500,158		8,495			508,653
Operating expenses
Transportation and processing costs	—		8,495			8,495
Production revenues less transportation and processing costs	$	500,158	$	—		$	500,158

Net income attributable to Parsley Energy, Inc. stockholders (in thousands)	$	113,309	$	—		$	113,309

Production:
Oil (MBbls)	6,763		—			6,763
Natural gas (MMcf) ⁽¹⁾	8,791		1,087			9,878
Natural gas liquids (MBbls) ⁽¹⁾	2,012		269			2,281
Total (MBoe)	10,240		450			10,690

Average daily production volume:
Oil (Bbls)	73,511		—			73,511
Natural gas (Mcf)	95,554		11,816			107,370
Natural gas liquids (Bbls)	21,870		2,923			24,793
Total (Boe)	111,304		4,892			116,196

Certain unit costs (per Boe) ⁽²⁾:
Lease operating expenses	$	3.88	$	(0.16	)	$	3.72
Transportation and processing costs	$	—	$	0.79		$	0.79
Production and ad valorem taxes	$	2.99	$	(0.13	)	$	2.86
Depreciation, depletion and amortization	$	15.37	$	(0.65	)	$	14.72
General and administrative expenses	$	3.67	$	(0.16	)	$	3.51




(1)	Natural gas and NGLs sales and production volumes for the three months ended September 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018.
(2)	Average costs per Boe for the three months ended September 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018.

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	Nine Months Ended September 30, 2018
	ASC 605		Adjustment			ASC 606
Production revenues (in thousands):
Oil sales	$	1,151,977	$	—		$	1,151,977
Natural gas sales ⁽¹⁾	38,189		4,280			42,469
Natural gas liquids sales ⁽¹⁾	152,236		16,953			169,189
Total production revenues	1,342,402		21,233			1,363,635
Operating expenses
Transportation and processing costs	—		21,233			21,233
Production revenues less transportation and processing costs	$	1,342,402	$	—		$	1,342,402

Net income attributable to Parsley Energy, Inc. stockholders (in thousands)	$	315,354	$	—		$	315,354

Production:
Oil (MBbls)	18,269		—			18,269
Natural gas (MMcf) ⁽¹⁾	25,060		2,609			27,669
Natural gas liquids (MBbls) ⁽¹⁾	5,329		701			6,030
Total (MBoe)	27,774		1,137			28,911

Average daily production volume:
Oil (Bbls)	66,919		—			66,919
Natural gas (Mcf)	91,795		9,557			101,352
Natural gas liquids (Bbls)	19,520		2,568			22,088
Total (Boe)	101,736		4,165			105,901

Certain unit costs (per Boe) ⁽²⁾:
Lease operating expenses	$	3.76	$	(0.15	)	$	3.61
Transportation and processing costs	$	—	$	0.73		$	0.73
Production and ad valorem taxes	$	2.96	$	(0.12	)	$	2.84
Depreciation, depletion and amortization	$	15.27	$	(0.60	)	$	14.67
General and administrative expenses	$	3.91	$	(0.16	)	$	3.75




(1)	Natural gas and NGLs sales and production volumes for the nine months ended September 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018.
(2)	Average costs per Boe for the nine months ended September 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018.

Changes to natural gas and NGLs sales were made in accordance with the control model defined in ASC 606. Under the new control model, we are required to identify and separately analyze each contract associated with revenues to determine the appropriate accounting application. We considered various indicators for contracts and the weighting of their relevance to determine when control transferred to the customer (such as whether raw gas is sold at the receipt point or residue gas and NGLs are sold at the tailgate of the gas processing plants). Based on this analysis, we concluded that the presence of product redelivery and take-in-kind rights, if substantive, are determinative indicators of control transferring at the tailgate if there is intent at contract inception. Additionally, we consider risk of loss an important indicator of when control transfers, which is comprised of risks associated with loss of product, exposure to product mix and recoveries and exposure to index prices versus actual prices. We also concluded that title, custody and acceptance are not determinative indicators of control, as such factors may be present in the case of a sale or the performance of a service.

As a result of this analysis, we modified our accounting and presentation of natural gas and NGLs sales, and transportation and processing costs, under certain marketing agreements. This is due to the conclusion that we represent the principal and the ultimate third party is our customer, which implies that we maintain control of the product through the tailgate

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of gas processing plants in certain natural gas processing and marketing agreements with certain midstream entities in accordance with the control model in ASC 606. This is a change from previous conclusions we reached for these agreements when utilizing the principal versus agent indicators under ASC Topic 605, Revenue Recognition, where we acted as the agent and the midstream processing entity acted as our customer. As a result, our presentation of revenues and expenses for these agreements has been modified. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Transportation and processing costs related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as Transportation and processing costs on our condensed consolidated statements of operations. Additionally, all references to production and per Boe unit costs reflect this adoption, which has the effect of increasing certain natural gas and NGLs volumes and revenues, offset by a corresponding transportation and processing expense, such that there is no change to reported net income. Refer to Note 3—Revenue from Contracts with Customers—Impact of ASC Topic 606 Adoption in our condensed consolidated financial statements for additional discussion.

All comparisons to prior period sales, expenses, production volumes and unit costs reflect the changes in reporting methodology for the three and nine months ended September 30, 2018. To provide additional insight, in the above tables, we have quantified the impact of the adoption of ASC 606 during the three and nine months ended September 30, 2018.

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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,
	2018		2017		2018		2017
Production revenues (in thousands):
Oil sales	$	424,549	$	198,865	$	1,151,977	$	546,676
Natural gas sales ⁽¹⁾	12,810		15,601		42,469		41,051
Natural gas liquids sales ⁽¹⁾	71,294		26,547		169,189		64,296
Total revenues	$	508,653	$	241,013	$	1,363,635	$	652,023

Average realized prices ⁽²⁾:
Oil, without realized derivatives (per Bbls)	$	62.78	$	45.80	$	63.06	$	46.91
Oil, with realized derivatives (per Bbls)	61.44		45.51		60.08		46.38
Natural gas, without realized derivatives (per Mcf)	1.30		2.49		1.53		2.55
Natural gas, with realized derivatives (per Mcf)	1.35		2.45		1.59		2.52
Natural gas liquids (per Bbls)	31.26		22.23		28.06		20.99
Average price per Boe, without realized derivatives	47.58		36.62		47.17		37.47
Average price per Boe, with realized derivatives	46.79		36.39		45.33		37.08

Production:
Oil (MBbls)	6,763		4,342		18,269		11,653
Natural gas (MMcf) ⁽¹⁾	9,878		6,265		27,669		16,105
Natural gas liquids (MBbls) ⁽¹⁾	2,281		1,194		6,030		3,063
Total (MBoe)	10,690		6,581		28,911		17,402

Average daily production volume:
Oil (Bbls)	73,511		47,196		66,919		42,685
Natural gas (Mcf)	107,370		68,098		101,352		58,993
Natural gas liquids (Bbls)	24,793		12,978		22,088		11,220
Total (Boe)	116,196		71,534		105,901		63,744



(1)	Natural gas and NGLs sales and associated production volumes for the three and nine months ended September 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018, as discussed in Factors Affecting the Comparability of our Financial Condition and Results of Operations—Impact of ASC Topic 606 Adoption.
(2)	Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains and losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Average realized oil price ($/Bbl)	$	62.78		$	45.80		$	63.06		$	46.91
Average NYMEX ($/Bbl)	$	69.44		$	48.20		$	66.80		$	49.36
Differential to NYMEX	$	(6.66	)	$	(2.40	)	$	(3.74	)	$	(2.45	)
Average realized oil price as a percentage of average NYMEX oil price	90		%	95		%	94		%	95		%
Average realized natural gas price ($/Mcf)	$	1.30		$	2.49		$	1.53		$	2.55
Average NYMEX ($/Mcf)	$	2.87		$	2.95		$	2.85		$	3.05
Differential to NYMEX	$	(1.57	)	$	(0.46	)	$	(1.32	)	$	(0.50	)
Average realized natural gas price as a percentage of average NYMEX gas price	45		%	84		%	54		%	84		%
Average realized NGLs price ($/Bbl)	$	31.26		$	22.23		$	28.06		$	20.99
Average NYMEX ($/Bbl)	$	69.44		$	48.20		$	66.80		$	49.36
Differential to NYMEX	$	(38.18	)	$	(25.97	)	$	(38.74	)	$	(28.37	)
Average realized NGLs price as a percentage of average NYMEX oil price	45		%	46		%	42		%	43		%

Oil, natural gas and NGLs revenues. Our oil, natural gas and NGLs revenues increased by $267.6 million, or 111%, to $508.7 million for the three months ended September 30, 2018 from $241.0 million for the three months ended September 30, 2017.

As shown in the following tables, from the three months ended September 30, 2017 to the three months ended September 30, 2018, the net dollar effect of the increase in oil and NGLs prices, as offset by the decrease in natural gas prices, was $123.6 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs was $144.0 million. Included in these changes are increases of $1.3 million and $7.2 million for natural gas and NGLs sales, respectively, which are related to the adoption of ASC 606 as discussed in Note 3—Revenue from Contracts With Customers to our condensed consolidated financial statements included elsewhere in this Quarterly Report and “Factors Affecting the Comparability of our Financial Condition and Results of Operations-Impact of ASC Topic 606 Adoption.”



	Change in prices			Production volumes	Total net dollar effect of change
Effect of change in price:				(in thousands)	(in thousands)
Oil (per Bbls)	$	16.98		6,763	$	114,801
Natural gas (per Mcf)	(1.19		)	9,878	(11,788		)
Natural gas liquids (per Bbls)	9.03			2,281	20,579
Total revenues due to change in price					$	123,592



	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)	2,421	$	45.80	$	110,883
Natural gas (MMcf)	3,613	2.49		8,997
Natural gas liquids (MBbls)	1,087	22.23		24,168
Total revenues due to change in production volumes				$	144,048

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Our oil, natural gas and NGLs revenues increased by $711.6 million, or 109%, to $1,363.6 million for the nine months ended September 30, 2018 from $652.0 million for the nine months ended September 30, 2017.

As shown in the following tables, from the nine months ended September 30, 2017 to the nine months ended September 30, 2018, the net dollar effect of the increase in oil and NGLs prices, as offset by the decrease in natural gas prices, was $309.5 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs was $402.1 million. Included in these changes are increases of $4.3 million and $17.0 million for natural gas and NGLs sales, respectively, which are related to the adoption of ASC 606 for the nine months ended September 30, 2018 as discussed in Note 3—Revenue from Contracts With Customers to our condensed consolidated financial statements included elsewhere in this Quarterly Report and “Factors Affecting the Comparability of our Financial Condition and Results of Operations-Impact of ASC Topic 606 Adoption.”



	Change in prices			Production volumes		Total net dollar effect of change
Effect of change in price:				(in thousands)		(in thousands)
Oil (per Bbls)	$	16.15		$	18,269	$	294,925
Natural gas (per Mcf)	(1.02		)	27,669		(28,059		)
Natural gas liquids (per Bbls)	7.07			6,030		42,612
Total revenues due to change in price						$	309,478



	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)	6,616	$	46.91	$	310,376
Natural gas (MMcf)	11,564	2.55		29,477
Natural gas liquids (MBbls)	2,967	20.99		62,281
Total revenues due to change in production volumes				$	402,134

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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,
	2018		2017		2018		2017
Operating expenses (in thousands):
Lease operating expenses	$	39,777	$	29,525	$	104,513	$	76,783
Transportation and processing costs	8,495		—		21,233		—
Production and ad valorem taxes	30,604		14,808		82,121		37,367
Depreciation, depletion and amortization	157,352		94,819		424,103		247,104
General and administrative expenses ⁽¹⁾	37,555		33,573		108,541		89,376
Exploration and abandonment costs	11,140		88		19,917		4,223
Acquisition costs	—		2,449		2		10,969
Accretion of asset retirement obligations	361		268		1,074		597
Other operating expenses	6,129		2,419		10,781		8,275
Total operating expenses	$	291,413	$	177,949	$	772,285	$	474,694

Expense per Boe⁽²⁾:
Lease operating expenses	$	3.72	$	4.49	$	3.61	$	4.41
Transportation and processing costs	0.79		—		0.73		—
Production and ad valorem taxes	2.86		2.25		2.84		2.15
Depreciation, depletion and amortization	14.72		14.41		14.67		14.20
General and administrative expenses	3.51		5.10		3.75		5.14
Exploration and abandonment costs	1.04		0.01		0.69		0.24
Acquisition costs	—		0.37		—		0.63
Accretion of asset retirement obligations	0.03		0.04		0.04		0.03
Other operating expenses	0.57		0.37		0.37		0.48
Total operating expenses per Boe	$	27.24	$	27.04	$	26.70	$	27.28


(1)	General and administrative expenses include stock-based compensation expense of $4.7 million and $15.1 million for the three and nine months ended September 30, 2018, respectively, as compared to $5.2 million and $14.6 million for the three and nine months ended September 30, 2017, respectively.


(2)	All unit costs for the three and nine months ended September 30, 2018 reflect the adoption of ASC 606, which had the effect of increasing certain natural gas and NGLs volumes. In turn, the increase in natural gas and NGLs volumes effectively decreased unit costs by approximately 4%.

Lease operating expenses. Lease operating expenses were $39.8 million and $104.5 million for the three and nine months ended September 30, 2018, respectively, as compared to $29.5 million and $76.8 million for the three and nine months ended September 30, 2017, respectively. The increase is primarily due to the increase in the number of our operated and non-operated wells.

On a per Boe basis, lease operating expenses decreased $0.77 per Boe, or 17%, to $3.72 for the three months ended September 30, 2018 from $4.49 for the three months ended September 30, 2017. The decrease in lease operating expenses per Boe is partially attributable to a greater portion of our production coming from horizontal wells. The decrease in lease operating expenses per Boe is also partially attributable to a 62% increase in production period over period.

On a per Boe basis, lease operating expenses decreased $0.80 per Boe, or 18%, to $3.61 for the nine months ended September 30, 2018 from $4.41 for the nine months ended September 30, 2017. The decrease in lease operating expenses per Boe is partially attributable to a greater portion of our production coming from horizontal wells. The decrease in lease operating expenses per Boe is also partially attributable to a 66% increase in production period over period.

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Transportation and processing costs. Transportation and processing costs were $8.5 million and $21.2 million for the three and nine months ended September 30, 2018, respectively. On a per Boe basis, transportation and processing costs were $0.79 and $0.73 per Boe for the three and nine months ended September 30, 2018, respectively. Transportation and processing costs represent third-party costs related to certain of our natural gas and NGLs marketing and processing agreements. Due to the adoption of ASC 606, we now report such costs separately. During the three and nine months ended September 30, 2017, these costs were included in our net natural gas and NGLs sales. Refer to Note 3—Revenue from Contracts with Customers—Impact of ASC Topic 606 Adoption in our condensed consolidated financial statements for additional discussion.

Production and ad valorem taxes. Production and ad valorem taxes were $30.6 million and $82.1 million for the three and nine months ended September 30, 2018, respectively, as compared to $14.8 million and $37.4 million for the three and nine months ended September 30, 2017, respectively. On a per Boe basis, production and ad valorem taxes increased from $2.25 per Boe for the three months ended September 30, 2017 to $2.86 per Boe for the three months ended September 30, 2018 and from $2.15 per Boe for the nine months ended September 30, 2017 to $2.84 per Boe for the nine months ended September 30, 2018.

Overall, for the three and nine months ended September 30, 2018, compared to the same periods in 2017, production taxes increased by approximately $13.2 million and $34.7 million, respectively, reflecting increased production volume and price during the periods and ad valorem taxes increased $2.6 million and $10.1 million over the same periods, reflecting higher property valuation assessments by local taxing authorities.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $157.4 million and $424.1 million for the three and nine months ended September 30, 2018, respectively, as compared to $94.8 million and $247.1 million for the three and nine months ended September 30, 2017, respectively.

These increases are largely attributable to acquisitions and development activity that resulted in a $2,245.7 million increase in costs subject to depletion as of September 30, 2018 as compared to September 30, 2017 and 62% and 66% increases in production during the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017. These increases were partially offset by a 41% increase in total proved reserves and a 60% increase in proved developed reserves as of September 30, 2018, as compared to September 30, 2017.

On a per Boe basis, DD&A expense increased to $14.72 for the three months ended September 30, 2018 from $14.41 during the three months ended September 30, 2017, and DD&A expense increased to $14.67 during the nine months ended September 30, 2018 from $14.20 during the nine months ended September 30, 2017, in each case primarily due to the increase in production volumes and reserves discussed above.

General and administrative expenses. General and administrative expenses were $37.6 million and $108.5 million for the three and nine months ended September 30, 2018, respectively, as compared to $33.6 million and $89.4 million for the three and nine months ended September 30, 2017, respectively. The increase is 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 $3.51 and $3.75 for the three and nine months ended September 30, 2018, respectively, as compared to $5.10 and $5.14 during the three and nine months ended September 30, 2017, respectively, in each case primarily as a result of production volume growth outpacing general and administrative expenses growth.

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
Leasehold abandonments	$	9,996	$	—		$	18,319	$	—
Geological and geophysical costs	1,094		(55		)	1,404		3,661
Other	50		143			194		562
Total exploration and abandonment costs	$	11,140	$	88		$	19,917	$	4,223

During the three and nine months ended September 30, 2018, we recognized leasehold abandonment expenses of approximately $10.0 million and $18.3 million, which primarily relates to expiring non-contiguous acreage in the Midland Basin. No such expenses were incurred during the three and nine months ended September 30, 2017.

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We recognized geological and geophysical (“G&G”) costs of $1.1 million and $1.4 million during the three and nine months ended September 30, 2018, respectively, as compared to ($0.1) million and $3.7 million during the three and nine months ended September 30, 2017, respectively. Our G&G costs consist of the expenses associated with acquiring and processing seismic data, geophysical data and core analysis, primarily relating to geoscientific analysis of our acreage. The decrease in G&G costs during the three and nine months ended September 30, 2018 reflects a reduction in our G&G related activity.

We recognized other exploration costs of $0.1 million and $0.2 million during the three and nine months ended September 30, 2018, respectively, as compared to $0.1 million and $0.6 million during the three and nine months ended September 30, 2017, respectively, which, in each case, are related to other exploration costs, which includes research and other similar costs.

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 which include non-recurring legal and other due diligence fees associated with certain acquisitions. During the three and nine months ended September 30, 2018, such acquisition costs were minimal.

Other operating expenses. During the three and nine months ended September 30, 2018, other operating expenses incurred during the normal course of business of our majority-owned subsidiary, Pacesetter, were $2.2 million and $6.9 million, respectively, as compared to $2.4 million and $7.2 million during the three and nine months ended September 30, 2017. As discussed in Note 6—Acquisitions and Divestitures to our condensed consolidated financial statements included elsewhere in this Quarterly Report, during the three months ended September 30, 2018, Pacesetter completed the sale of all of its physical assets.

In addition, we incurred idle charges, which constitute other operating expenses, of $3.9 million for the three and nine months ended September 30, 2018 and $1.1 million during the nine months ended September 30, 2017. The idle charges are a result of nonrecurring costs incurred associated with temporarily idled contracted assets and services. There was no such activity for the three months ended September 30, 2017.

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,
	2018			2017			2018			2017
Other income (expense) (in thousands):
Interest expense, net	$	(32,854	)	$	(22,879	)	$	(98,580	)	$	(64,979	)
Gain on sale of property	1,383			—			6,438			—
Loss on early extinguishment of debt	—			—			—			(3,891		)
(Loss) gain on derivatives	(22,514		)	(61,955		)	(42,773		)	6,175
Change in TRA liability	—			—			(82		)	(20,549		)
Interest income	1,055			1,013			4,864			5,562
Other (loss) income	(76		)	508			459			1,281
Total other expense, net	$	(53,006	)	$	(83,313	)	$	(129,674	)	$	(76,401	)

Interest expense, net. Interest expense, net for the three and nine months ended September 30, 2018 was $32.9 million and $98.6 million, respectively, as compared to $22.9 million and $65.0 million, respectively, for the three and nine months ended September 30, 2017. The increase resulted from increased weighted average debt outstanding, as discussed in Note 8—Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report.

Gain on sale of property. We recognized a gain on the sale of property of $1.4 million and $6.4 million during the three and nine months ended September 30, 2018, respectively, as discussed in Note 6—Acquisitions and Divestitures to our condensed consolidated financial statements included elsewhere in this Quarterly Report. We recognized no gain or loss on the sale of property during the three and nine months ended September 30, 2017.

Loss on early extinguishment of debt. We recorded a $3.9 million loss on early extinguishment of debt during the nine months ended September 30, 2017 due to the redemption of our then outstanding 7.500% senior unsecured notes due 2022 in

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January 2017. There was no such activity for the three and nine months ended September 30, 2018 or the three months ended September 30, 2017.

(Loss) gain on derivatives. We recognized a loss on derivatives of $22.5 million and $42.8 million, during the three and nine months ended September 30, 2018, respectively, and a loss on derivatives of $62.0 million and a gain on derivatives of $6.2 million during the three and nine months ended September 30, 2017, respectively. The change during the three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017, is primarily a result of higher commodity prices, which decreased the value of our derivative portfolio.

Change in TRA liability. We recorded a $0.1 million expense during the nine months ended September 30, 2018, associated with an increase in the TRA liability resulting from the reversal of the valuation allowance recorded during 2017. During the nine months ended September 30, 2017 we recorded a $20.5 million expense associated with an increase in the TRA liability resulting from the reversal of the valuation allowance recorded during 2016. During the three months ended September 30, 2018 and 2017, we recorded no change to the TRA liability.

Interest income. Interest income was $1.1 million and $4.9 million during the three and nine months ended September 30, 2018, respectively, as compared to $1.0 million and $5.6 million during the three and nine months ended September 30, 2017, respectively. The change during the three and nine months ended September 30, 2018, as compared to the three and nine months ended September 30, 2017, is a result of decreased dividend and interest income offset by increased amortization, which relates to our held to maturity securities, as discussed in Note 15—Disclosures about Fair Value of Financial Instruments.

Other (loss) income. Other income was $0.5 million, $1.3 million and $0.5 million for the three and nine months ended September 30, 2017 and the nine months ended September 30, 2018, respectively. Other loss was $0.1 million for the three months ended September 30, 2018. The decrease for the three months ended September 30, 2018, as compared to the same respective period in 2017 is attributable to an increase in income from our equity investment in Spraberry Production Services, LLC offset by decreases in other miscellaneous items. The decrease for the nine months ended September 30, 2018, as compared to the same respective period in 2017, is primarily attributable to a decrease in fair value adjustments associated with money market accounts as well as decreases in other miscellaneous items.

Income Tax Expense

During the three and nine months ended September 30, 2018, we recognized income tax expense of $32.5 million and $89.0 million, respectively. During the three and nine months ended September 30, 2017, we recognized income tax benefit of $5.1 million and income tax expense of $25.5 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 and state income taxes.

Capital Requirements and Sources of Liquidity

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Capital expenditures	$	444,314	$	306,788	$	1,345,511	$	790,193

Our 2018 budget for capital development expenditures is approximately $1,650.0 million to $1,750.0 million. Approximately 85% to 90% of the budget is expected to be used for drilling and completions and approximately 10% to 15% of the budget is expected to be used for infrastructure and other expenditures. Our capital budget excludes any amounts that may be paid for acquisitions. For the year ended December 31, 2017, our aggregate drilling and completion expenditures were $1,049.6 million and our infrastructure and other expenditures were $157.8 million for a total of $1,207.4 million. The amount and timing of 2018 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2018 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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Based upon current oil and natural gas price expectations for fiscal year 2018, we believe that our cash on hand, cash flow from operations and borrowings under the Revolving Credit Agreement will be sufficient to fund our operations through 2018. 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, 2018, our liquidity was as follows (in millions):



Cash and cash equivalents	$	167.8
Revolving Credit Agreement availability	991.3
Liquidity	$	1,159.1

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, 2017 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 2018 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. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Cash Flows

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



	Nine Months Ended September 30,
	2018			2017
Net cash provided by operating activities	$	899,877		$	492,421
Net cash used in investing activities	(1,273,057		)	(2,880,228		)
Net cash (used in) provided by financing activities	(13,189		)	2,498,133

Cash flows provided by operating activities. Net cash provided by operating activities was approximately $899.9 million and $492.4 million for the nine months ended September 30, 2018 and 2017, respectively. Net cash provided by operating activities increased primarily due to a $716.0 million increase in total revenues during the nine months ended September 30, 2018 over the nine months ended September 30, 2017 associated with increased production volumes and an overall increase in average realized prices. This was offset by a an increase in cash based operating expenses, including lease operating expenses, transportation and processing costs, production and ad valorem taxes, cash general and administrative expenses and acquisition costs associated with our increased asset base.

Cash flows used in investing activities. Net cash used in investing activities was approximately $1,273.1 million and $2,880.2 million for the nine months ended September 30, 2018 and 2017, respectively. The reduction in the amount of cash used in investing activities was due primarily to the $2,034.7 million decrease in acquisition costs during the nine months ended September 30, 2018 over the nine months ended September 30, 2017, offset by the $631.6 million increase in development costs related to our oil and natural gas properties during the nine months ended September 30, 2018 over the nine months ended September 30, 2017. Please refer to Note 6—Acquisitions and Divestitures to our condensed consolidated financial statements included elsewhere in this Quarterly Report for additional discussion related to acquisitions.

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Cash flows (used in) provided by financing activities. Net cash used in financing activities was $13.2 million and net cash provided by financing activities was $2,498.1 million for the nine months ended September 30, 2018 and 2017, respectively. Net cash provided by financing activities decreased by $2,511.3 million during the nine months ended September 30, 2018 as a result of the Company not completing any debt or equity issuances in the period. During the nine months ended September 30, 2018, we had payments on long-term debt of $2.2 million and $10.9 million related to the vesting of RSUs and PSUs, respectively. 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 were offset by payments on long-term debt of $68.4 million.

Capital Sources

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

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

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

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

Derivative activity. We plan to continue our practice of entering into hedging arrangements to 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.

Working Capital

Our working capital totaled ($181.3) million and $307.4 million at September 30, 2018 and December 31, 2017, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents and short-term investments totaled $167.8 million and $703.5 million at September 30, 2018 and December 31, 2017, respectively. The $535.7 million decrease in cash and cash equivalents and short-term investments is primarily attributable to the development of our oil and natural gas properties as well as acquisitions described in Note 6—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, 2018 to the methodology applied by management for critical accounting policies previously disclosed in the Annual Report. Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in the Annual Report for further description of our critical accounting policies.

Off-Balance Sheet Arrangements

We do not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to our condensed consolidated financial statements.

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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, 2017, except as described below.

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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.

We enter into multiple types of commodity derivative contracts to (i) reduce the effect of price volatility on our oil and natural gas revenues and (ii) support our annual capital budgeting and expenditure plans. We plan to continue our practice of entering into such transactions 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, 2018, see Note 4—Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this Quarterly Report.

We do not require collateral from our counterparties for entering into derivative instruments, so in order to mitigate the credit risk associated with such derivative instruments, we typically enter into an International Swap Dealers Association Master Agreement (“ISDA Agreement”) with 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, 2018, the fair market value of our oil and natural gas derivative contracts was a net liability of $50.0 million, including net deferred premium payables of $58.6 million. The deferred premium payable is a fixed amount and is not marked to fair market value. As of September 30, 2018, the fair market value of our oil derivative contracts was a net liability of $50.1 million. Based on our open oil derivative positions at September 30, 2018, a 10% increase in the NYMEX WTI price would increase our net oil derivative liability by approximately $27.4 million, while a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $20.1 million. As of September 30, 2018, the fair market value of our natural gas derivative contracts was a net asset of less than $0.1 million. Based on our open gas derivative positions at September 30, 2018, a 10% increase or decrease in the NYMEX Henry Hub price would have a nominal impact. Please read “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Realized Prices on the Sale of Oil, Natural Gas, and NGLs.”

Counterparty Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require 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 the Revolving Credit Agreement, each of whom has an investment grade rating.

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Interest Rate Risk

Our market risk exposure related to changes in interest rates relates primarily to debt obligations and the amount of interest we earn on our short-term investments. As of September 30, 2018, we had $2.2 billion (excluding capital lease obligations) of fixed-rate long-term debt outstanding with a weighted average interest rate of 5.6%. Although near term changes may impact the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss. We are exposed to changes in interest rates as a result of the Revolving Credit Agreement, which requires us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. As of September 30, 2018, however, we had no outstanding borrowings under the Revolving Credit Agreement and therefore an increase in interest rates will not result in increased interest expense until such time that we determine to make borrowings under the Revolving Credit Agreement. We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents and short-term investment balances. As of September 30, 2018, our cash and cash equivalents and short-term investments totaled $167.8 million, approximately 61% of which was invested in money market funds and commercial paper with major financial institutions. A change in the interest rate applicable to the Revolving Credit Agreement or short-term investments would have a de minimis impact.

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Item 4. Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2018. 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, 2018 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended September 30, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

The following sets forth information with respect to our repurchases of shares of Class A Common Stock during the three months ended September 30, 2018:



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 2018	2,189	$	31.90	—	$	—
August 2018	—	$	—	—	$	—
September 2018	—	$	—	—	$	—
Total	2,189	$	31.90	—	$	—



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

Item 6. Exhibits

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

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EXHIBIT INDEX



Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
3.2		Amended and Restated Bylaws of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on October 30, 2018).
10.1†		Employment, Confidentiality and Non-Competition Agreement, dated September 26, 2018, by and between Parsley Energy Operations, LLC and David Dell’Osso (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 September 26, 2018).
10.2†		Indemnification Agreement, dated September 26, 2018, by and between Parsley Energy, Inc. and David Dell’Osso (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 September 26, 2018).
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.



†	Management contract or compensatory plan or arrangement.



*	Filed herewith.



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

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SIGNATURES

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



	PARSLEY ENERGY, INC.

November 2, 2018	By:	/s/ Bryan Sheffield
		Bryan Sheffield
		Chairman and Chief Executive Officer (Principal Executive Officer)


November 2, 2018	By:	/s/ Ryan Dalton
		Ryan Dalton
		Executive Vice President—Chief Financial Officer (Principal Accounting and Financial Officer)

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

Emerging growth company ¨

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