Parsley Energy (PE) SEC Quarterly Report (10-Q) for Q1 2016

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2016

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

For the transition period from to

Commission File Number: 001-36463

PARSLEY ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

(737) 704-2300

(Registrant's telephone number, including area code)

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

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

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

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

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ N o x

As of May 6, 2016, the registrant had 157,613,283 shares of Class A common stock and 32,145,296 shares of Class B common stock outstanding.

PARSLEY ENERGY, INC.

FORM 10-Q

QUARTERLY PERIOD ENDED MARCH 31, 2016

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 201 5	7
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2016 and 2015	8
	Condensed Consolidated Statement of Changes in Equity for the three months ended March 31, 2016	9
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2016 and 2015	10
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	38

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 6.	Exhibits	39
	Signatures	40

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 keep in mind the risk factors and other cautionary statements described under, but not limited to, the heading "Item 1A. Risk Factors" and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2015 (the "Annual Report") and other filings with the United States Securities and Exchange Commission ("SEC"). These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

·	business strategy;

reserves;

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

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

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

·	realized oil, natural gas and natural gas liquids (NGLs) prices;

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

·	hedging strategy and results;

·	future drilling plans;

·	competition and government regulations;

·	ability to obtain permits and governmental approvals;

·	pending legal or environmental matters;

·	marketing of oil, natural gas and NGLs;

·	leasehold or business acquisitions;

·	costs of developing our properties;

·	general economic conditions;

·	credit markets;

·	uncertainty regarding our future operating results; and

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

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

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)	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.

(9)

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 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 or G&G costs.

(ii)

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

(iii)

Dry hole contributions and bottom hole contributions.

(iv)

Costs of drilling and equipping exploratory wells.

(v)

Costs of drilling exploratory-type stratigraphic test wells.

(vi)

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

(10)	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.

(11)

Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC's Regulation S-X, Rule 4-10(a)(15).

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

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

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

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

(16)

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.

(17)	LIBOR . London Interbank Offered Rate.

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

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

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

(21)	MMBtu . One million British thermal units.

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

(23)	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.

(24)	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 50% interest in 100 gross acres owns 50 net acres.

(25)	NYMEX . The New York Mercantile Exchange.

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

(27)	PE Units . The single class of units in which all of the membership interests (including outstanding incentive units) in Parsley Energy, LLC were converted to in connection with our initial public offering.

(28)	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.

(29)

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

(30)	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.

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.

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.

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.

(31)	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).

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

(33)	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.

(34)

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.

(35)	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.

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

(37)	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.

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

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

(40)	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.

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

(42)	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.

PART 1: FINANCIAL INFORMATION

Item 1: Financial Statements

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2016			December 31, 2015
	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	28,310		$	343,084
Restricted cash		1,607			1,139
Accounts receivable:
Joint interest owners and other		24,755			14,998
Oil and gas		26,195			21,219
Related parties		1,247			390
Short-term derivative instruments, net		72,081			83,262
Other current assets		18,346			24,234
Total current assets		172,541			488,326
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method		2,566,038			2,246,161
Accumulated depreciation, depletion and impairment		(338,199	)		(290,186	)
Total oil and natural gas properties, net		2,227,839			1,955,975
Other property, plant and equipment, net		31,413			29,778
Total property, plant, and equipment, net		2,259,252			1,985,753
NONCURRENT ASSETS
Long-term derivative instruments, net		20,119			25,839
Other noncurrent assets		4,622			5,182
Total noncurrent assets		24,741			31,021
TOTAL ASSETS	$	2,456,534		$	2,505,100

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses	$	142,856		$	151,221
Revenue and severance taxes payable		35,584			37,109
Current portion of long-term debt		997			951
Short-term derivative instruments, net		30,610			34,518
Current portion of asset retirement obligations		4,986			4,698
Total current liabilities		215,033			228,497
NONCURRENT LIABILITIES
Long-term debt		546,817			546,832
Asset retirement obligations		14,079			13,522
Deferred tax liability		53,335			62,962
Payable pursuant to tax receivable agreement		51,504			51,504
Long-term derivative instruments, net		11,981			15,142
Total noncurrent liabilities		677,716			689,962
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, 136,732,438 shares issued and 136,625,783 shares outstanding at March 31, 2016 and 136,728,906 shares issued and 136,623,407 shares outstanding at December 31, 2015		1,360			1,360
Class B, $0.01 par value, 125,000,000 shares authorized, 32,145,296 issued and outstanding at March 31, 2016 and December 31, 2015		321			321
Additional paid in capital		1,254,809			1,252,020
(Accumulated deficit) retained earnings		(8,427	)		10,868
Treasury stock, at cost, 106,655 shares and 105,421 at March 31, 2016 and December 31, 2015		(96	)		(77	)
Total stockholders' equity		1,247,967			1,264,492
Noncontrolling interest		315,818			322,149
Total equity		1,563,785			1,586,641
TOTAL LIABILITIES AND EQUITY	$	2,456,534		$	2,505,100

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

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2016			2015
	(In thousands, except per share data)
REVENUES
Oil sales	$	52,031		$	43,688
Natural gas sales		5,543			6,956
Natural gas liquids sales		4,694			4,567
Total revenues		62,268			55,211
OPERATING EXPENSES
Lease operating expenses		13,898			16,398
Production and ad valorem taxes		4,195			4,495
Depreciation, depletion and amortization		49,384			37,381
General and administrative expenses (including stock-based compensation of $2,759 and $1,641 for the three months ended March 31, 2016 and 2015)		19,299			12,981
Exploration costs		688			3,219
Accretion of asset retirement obligations		170			249
Rig termination costs		-			5,100
Other operating expenses		896			-
Total operating expenses		88,530			79,823
OPERATING LOSS		(26,262	)		(24,612	)
OTHER INCOME (EXPENSE)
Interest expense, net		(11,289	)		(11,841	)
Gain on sale of property		350			-
Derivative income		2,088			7,142
Other income (expense)		(146	)		279
Total other income (expense), net		(8,997	)		(4,420	)
LOSS BEFORE INCOME TAXES		(35,259	)		(29,032	)
INCOME TAX BENEFIT		9,568			5,474
NET LOSS		(25,691	)		(23,558	)
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS		6,337			6,534
NET LOSS ATTRIBUTABLE TO PARSLEY ENERGY, INC. STOCKHOLDERS	$	(19,354	)	$	(17,024	)

Net loss per common share:
Basic	$	(0.14	)	$	(0.17	)
Diluted	$	(0.14	)	$	(0.17	)
Weighted average common shares outstanding:
Basic		135,963			101,273
Diluted		135,963			101,273

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

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			(Accumulated deficit) retained earnings			Treasury stock		Treasury stock			Total stockholders' equity			Noncontrolling interest			Total equity
(In thousands)
Balance at December 31, 2015		136,729			32,145	$	1,360	$	321	$	1,252,020		$	10,868			105	$	(77	)	$	1,264,492		$	322,149		$	1,586,641
Adoption of ASU 2016-09		-			-		-		-		-			59			-		-			59			-			59
Restated balance		136,729			32,145		1,360		321		1,252,020			10,927			105		(77	)		1,264,551			322,149			1,586,700
Issuance costs, net of underwriters discount and expenses		-			-		-		-		36			-			-		-			36			-			36
Change in equity due to issuance of PE Units by Parsley LLC		-			-		-		-		(6	)		-			-		-			(6	)		6			-
Vesting of restricted stock unit		4			-		-		-		-			-			-		-			-			-			-
Repurchase of restricted stock		(1	)		-		-		-		-			-			1		(19	)		(19	)		-			(19	)
Stock-based compensation		-			-		-		-		2,759			-			-		-			2,759			-			2,759
Net loss		-			-		-		-		-			(19,354	)		-		-			(19,354	)		(6,337	)		(25,691	)
Balance at March 31, 2016		136,732			32,145	$	1,360	$	321	$	1,254,809		$	(8,427	)		106	$	(96	)	$	1,247,967		$	315,818		$	1,563,785

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

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2016			2015
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(25,691	)	$	(23,558	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		49,384			37,381
Exploration costs		82			1,716
Accretion of asset retirement obligations		170			249
Amortization and write off of deferred loan origination costs		588			1,108
Amortization of bond premium		(191	)		(191	)
Deferred income tax benefit		(9,568	)		(5,474	)
Stock-based compensation		2,759			1,641
Derivative income		(2,088	)		(7,142	)
Net cash received for derivative settlements		21,988			13,196
Net cash (paid) received for option premiums		(488	)		17,398
Net premiums received (paid) on options that settled during the period		10,414			(136	)
Changes in operating assets and liabilities, net of acquisitions:
Restricted cash		(468	)		-
Accounts receivable		(14,733	)		4,547
Accounts receivable-related parties		(857	)		1,822
Materials and supplies		-			(575	)
Other current assets		(14,108	)		2
Other noncurrent assets		347			(97	)
Accounts payable and accrued expenses		3,889			(22,865	)
Revenue and severance taxes payable		(1,524	)		(661	)
Other noncurrent liabilities		-			(374	)
Net cash provided by operating activities		19,905			17,987
CASH FLOWS FROM INVESTING ACTIVITIES:
Development of oil and natural gas properties		(122,623	)		(117,930	)
Acquisitions of oil and natural gas properties		(208,832	)		(21,722	)
Additions to other property and equipment		(3,004	)		(4,567	)
Other investing activities		-			(925	)
Net cash used in investing activities		(334,459	)		(145,144	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on long-term debt		(236	)		(120,164	)
Debt issuance costs		(1	)		-
Proceeds from issuance of common stock, net		36			224,007
Repurchase of restricted stock		(19	)		-
Net cash (used in) provided by financing activities		(220	)		103,843
Net decrease in cash and cash equivalents		(314,774	)		(23,314	)
Cash and cash equivalents at beginning of period		343,084			50,550
Cash and cash equivalents at end of period	$	28,310		$	27,236
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	21,211		$	21,262
Cash paid for income taxes	$	315		$	-
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate	$	675		$	73
(Reductions) additions to oil and natural gas properties - change in capital accruals	$	(12,254	)	$	3,802
Additions to other property and equipment funded by capital lease borrowings	$	84		$	-

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

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 on December 11, 2013, pursuant to the laws of the State of Delaware, and is engaged in the acquisition and development of unconventional oil and natural gas reserves located in the Permian Basin, which is located in West Texas and Southeastern New Mexico.

Public Offering of Common Stock

On April 4, 2016, the Company entered into an agreement to sell 20,987,500 shares of Class A Common Stock, par value $0.01 per share ("Class A Common Stock"), (including 2,737,500 shares issued pursuant to the underwriters' option to purchase additional shares) at a price of $21.40 per share to in an underwritten public offering (the "April Offering"). The April Offering closed on April 8, 2016 and resulted in gross proceeds of approximately $449.1 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $433.1 million. Please refer to Note 14-Subsequent Events for additional discussion.

NOTE 2. BASIS OF PRESENTATION

These condensed consolidated financial statements include the accounts of Parsley Energy, Inc. and its majority-owned subsidiary, Parsley Energy, LLC ("Parsley LLC"), and its wholly owned subsidiaries: (i) Parsley Energy, L.P. ("Parsley LP"), (ii) Parsley Energy Management, LLC (the "General Partner"), (iii) Parsley Energy Operations, LLC ("Operations") and its wholly owned subsidiary, Parsley Energy Aviation, LLC, and (iv) Parsley Finance Corp ("Finance Corp"). These condensed consolidated financial statements also include the accounts of Pacesetter Drilling, LLC, a majority-owned subsidiary of Operations. Parsley LP owns a 42.5% noncontrolling interest in Spraberry Production Services, LLC ("SPS"). The Company accounts for its investment in SPS using the equity method of accounting. All significant intercompany and intra-company balances and transactions have been eliminated.

Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted. We believe the disclosures made are adequate to make the information not misleading. We recommend that these condensed consolidated financial statements should be read in conjunction with the Company's audited consolidated financial statements and related notes thereto included in the Annual Report .

In the opinion of management, 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 months ended March 31, 2016, is not necessarily indicative of the operating results of the entire fiscal year ending December 31, 2016.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Use of Estimates

These condensed consolidated financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board ("FASB") and by the SEC and (2) 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. Our management believes the major estimates and assumptions impacting our condensed consolidated financial statements are the following:

●

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

●

estimates of asset retirement obligations;

●

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

●

impairment of undeveloped properties and other assets;

●

depreciation of property and equipment; and

●

valuation of commodity derivative instruments.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

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.

Change in Accounting Principle

The Company adopted Accounting Standards Update ("ASU") 2015-03, Interest-Imputation of Interest (Subtopic 935-30): Simplifying the Presentation of Debt Issuance Costs , effective January 1, 2016. This standard requires companies that have historically presented debt issuance costs as an asset to present those costs as a direct deduction from the carrying amount of the underlying debt liability. To the extent that there are no borrowings under the amended and restated credit agreement with Wells Fargo Bank, National Association, as administrative agent (as amended, the "Revolving Credit Agreement"), the related deferred loan costs will continue to be classified as an asset. The guidance required retrospective application in the condensed consolidated financial statements. The Company had no borrowings outstanding under the Revolving Credit Agreement at March 31, 2016 and December 31, 2015, as such, approximately $2.1 million and $2.3 million, respectively, of deferred loan costs related to the Revolving Credit Agreement are included in "Other noncurrent assets." The Company's 7.500% senior notes due 2022 (the "Notes") are presented net of approximately $8.7 million and $9.1 million of deferred loan costs at March 31, 2016 and December 31, 2015, respectively.

The Company adopted ASU 2016-09, Compensation-Stock Compensation (Topic 718)-Improvements to Employee Share-Based Payment Accounting , effective January 1, 2016. This ASU is intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, including interim periods within those annual periods, and early application is permitted as of the beginning of an interim or annual reporting period. The ASU did not have a material effect on the Company's financial statements and related disclosures.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current presentation.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Recent Ac counting Pronouncements

In May 2014, March 2016 and April 2016, the FASB issued ASU Nos. 2014-09, 2016-08 and 2016-10, respectively, Revenue from Contracts with Customers , which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers amongst other things. The ASUs will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard will be effective for the Company on January 1, 2018. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09, 2016-08 and 2016-10 will have on its condensed consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

In May 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory , which requires entities that value inventory using the first-in, first-out or average cost method to measure inventory at the lower of cost and net realizable value. The amended guidance will be effective for the Company for fiscal years beginning after December 15, 2016, and for interim periods within those years. The amended guidance must be applied on a prospective basis and is not expected to materially affect the Company's condensed consolidated financial statements or notes to the condensed consolidated financial statements.

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

In March 2016, the FASB issued ASU No. 2016-07, Investments-Equity Method and Joint Ventures (Topic 323) as part of the simplification initiative, which eliminates the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2016. The amendments should be applied prospectively upon their effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Early adoption is permitted for any entity in any interim or annual period. The amended guidance is not expected to materially affect the Company's condensed consolidated financial statements or notes to the condensed consolidated financial statements.

NOTE 3. DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Instruments and Concentration of Risk

Objective and Strategy

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

The Company uses put spread options to manage commodity price risk for NYMEX WTI. A put spread option is a combination of two options: a purchased put and a sold put. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price plus the excess of the purchased put strike price over the sold put strike price.

Additionally, the Company uses basis swap contracts to mitigate basis risk caused by the volatility of the Company's basis differentials. The basis swap contracts establish the differential between Cushing WTI prices and the relevant price index at which oil production is sold.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Oil Production Derivative Activities

All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, NYMEX WTI oil prices. The Company uses put spread options to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and the actual index prices at which the oil is sold.

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

Crude Options	Nine Months Ending December 31, 2016			Year Ending December 31, 2017
Purchased:
Puts (1)
Notional (MBbl)		5,875			4,134
Weighted average strike price	$	49.78		$	46.88
Sold:
Puts (1)
Notional (MBbl)		(5,875	)		(4,134	)
Weighted average strike price	$	35.47		$	32.96
Basis swap contracts: (2)
Midland-Cushing index swap volume (MBbl)		1,516			4,290
Price differential ($/Bbl)	$	(0.87	)	$	(1.03	)

(1)	The Company excluded from the tables above 11,199 notional MBbls with a fair value of $221.0 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.

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 Company recognized income from its derivative activities of $2.1 million and $7.1 million for the three months ended March 31, 2016 and 2015, respectively. The income is included in the condensed consolidated statements of operations line item, "Derivative income." The fair value of the derivative instruments is discussed in Note 13-Disclosures about Fair Value of Financial Instruments.

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 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 months ended March 31, 2016 and 2015, the Company did not receive or post any margins in connection with collateralizing its derivative positions.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table presents the Comp any's net exposure from its offsetting derivative asset and liability positions, as well as cash collateral on deposit with the brokers as of the reporting dates indicated (in thousands):

	Gross Amount			Netting Adjustments			Net Exposure
March 31, 2016
Derivative assets with right of offset or master netting agreements	$	313,177		$	(220,977	)	$	92,200
Derivative liabilities with right of offset or master netting agreements		(263,568	)		220,977			(42,591	)

December 31, 2015
Derivative assets with right of offset or master netting agreements	$	407,052		$	(297,951	)	$	109,101
Derivative liabilities with right of offset or master netting agreements		(347,611	)		297,951			(49,660	)

Concentration of Credit Risk

The financial integrity of the Company's exchange-traded contracts is assured by NYMEX through systems of financial safeguards and transaction guarantees, and is therefore subject to nominal credit risk. Over-the-counter traded options expose the Company to counterparty credit risk. These over-the-counter options are entered into with a large multinational financial institution with investment grade credit rating or through brokers that require all the transaction parties to collateralize their open option positions. The gross and net credit exposure from our commodity derivative contracts as of March 31, 2016 and December 31, 2015 is summarized in the table above.

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 has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and its counterparties and brokers with rights of net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The Company routinely exercises its contractual right to offset realized gains against realized losses when settling with derivative counterparties. The Company did not incur any losses due to counterparty bankruptcy filings during the three months ended March 31, 2016 or the year ended December 31, 2015.

Credit Risk Related Contingent Features in Derivatives

Certain commodity derivative instruments contain provisions that require the Company to either post additional collateral or immediately settle any outstanding liability balances upon the occurrence of a specified credit risk related event. These events, which are defined by the existing commodity derivative contracts, are primarily downgrades in the credit ratings of the Company and its affiliates. None of the Company's commodity derivative instruments were in a net liability position with respect to any individual counterparty at March 31, 2016 or December 31, 2015.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 4. PROPE RTY, PLANT AND EQUIPMENT

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

	March 31, 2016			December 31, 2015
Oil and natural gas properties:
Subject to depletion	$	1,822,014		$	1,627,367
Not subject to depletion
Incurred in 2016		198,231			-
Incurred in 2015		54,130			118,101
Incurred in 2014 and prior		491,663			500,693
Total not subject to depletion		744,024			618,794
Gross oil and natural gas properties		2,566,038			2,246,161
Accumulated depreciation, depletion and impairment		(338,199	)		(290,186	)
Oil and natural gas properties, net		2,227,839			1,955,975
Other property and equipment		40,340			37,253
Less accumulated depreciation		(8,927	)		(7,475	)
Other property and equipment, net		31,413			29,778
Total property, plant, and equipment, net	$	2,259,252		$	1,985,753

Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs and current drilling projects. At March 31, 2016 and December 31, 2015, the Company had excluded $744.0 million and $618.8 million, respectively, of capitalized costs from depletion.

As the Company's exploration and development work progresses and the reserves on the Company's properties are proven, capitalized costs attributed to the properties are subject to DD&A. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated reservoir. Depletion expense on capitalized oil and gas property was $47.9 million and $36.4 million for the three months ended March 31, 2016 and 2015, respectively. The Company had no exploratory wells in progress at March 31, 2016 or December 31, 2015.

NOTE 5. ACQUISITIONS OF OIL AND GAS PROPERTIES

The Company acquired $12.9 million and $20.1 million of leasehold during the three months ended March 31, 2016 and 2015, respectively. The Company reflected $12.1 million and $19.1 million of the acquisition costs as part of costs not subject to depletion and $0.8 million and $1.0 million as part of its cost subject to depletion within its oil and gas properties for the periods ended March 31, 2016 and 2015, respectively.

In addition, during the three months ended March 31, 2016 and 2015, the Company acquired certain working interests as described below. These working interest 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.

During the three months ended March 31, 2016 and 2015, the Company acquired, from unaffiliated individuals and entities, working interests in wells through a number of separate, individually negotiated transactions for an aggregate total cash consideration of $195.9 million and $1.6 million, respectively. The Company reflected $41.8 million and $1.3 million of the total consideration paid as part of its cost subject to depletion within its oil and gas properties and $154.1 million and $0.3 million as unproved leasehold costs within its oil and gas periods for the periods ended March 31, 2016 and 2015, respectively. The revenues and operating expenses attributable to the working interest acquisitions during the three months ended March 31, 2016 and 2015, were not material.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 6. ASSET RETIREMENT OBLIGATIONS

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

The following table summarizes the changes in the Company's asset retirement obligations for the three months ended March 31, 2016 (in thousands):

	March 31, 2016
Asset retirement obligations, beginning of period	$	18,220
Additional liabilities incurred		664
Accretion expense		170
Revision of estimates		11
Asset retirement obligations, end of period	$	19,065

NOTE 7. DEBT

The Company's debt consists of the following (in thousands):

	March 31, 2016			December 31, 2015
Revolving Credit Agreement	$	-		$	-
7.500% senior unsecured notes due 2022		550,000			550,000
Capital leases		2,065			2,215
Total debt		552,065			552,215
Debt issuance costs on 7.500% senior unsecured notes due 2022		(8,719	)		(9,092	)
Premium on 7.500% senior unsecured notes due 2022		4,468			4,660
Less: current portion		(997	)		(951	)
Total long-term debt	$	546,817		$	546,832

Revolving Credit Agreement

As of March 31, 2016, the Borrowing Base (as defined therein) under the Revolving Credit Agreement was $575.0 million, with a commitment level of $575.0 million. There were no borrowings outstanding and $0.3 million in letters of credit outstanding as of March 31, 2016, resulting in availability of $574.7 million.

As of March 31, 2016, letters of credit under the Revolving Credit Agreement had a weighted average interest rate of 1.5%.

Covenant Compliance

The Revolving Credit Agreement and the indenture governing the Notes restrict our ability and the ability of certain of our 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 our capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our 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 when 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 indenture) 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 decline subsequently to below investment grade, the suspended covenants would be reinstated.

As of March 31, 2016, the Company was in compliance with all required covenants under the Revolving Credit Agreement and the indenture governing the Notes.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Principal Maturities of Debt

Principal maturities of debt outstanding at March 31, 2016 are as follows (in thousands):

2016	$	738
2017		1,027
2018		294
2019		6
2020		-
Thereafter		550,000
Total	$	552,065

Interest Expense

The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2016 and 2015 (in thousands):

	Three Months Ended March 31,
	2016			2015
Cash payments for interest	$	21,211		$	21,262
Change in interest accrual		(10,313	)		(10,380	)
Amortization of deferred loan origination costs		588			494
Write-off of deferred loan origination costs		-			614
Amortization of bond premium		(191	)		(191	)
Other interest (expense) income		(6	)		42
Total interest expense, net	$	11,289		$	11,841

NOTE 8. EQUITY

Earnings per Share

Basic earnings per share ("EPS") measures the performance of an entity over the reporting period. Diluted earnings per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the "if-converted" method to determine the potential dilutive effect of its Class B common stock, par value $0.01 per share ("Class B Common Stock") and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and restricted stock units. For the three months ended March 31, 2016 and 2015, Class B Common Stock, unvested restricted stock and restricted stock unit awards were not recognized in dilutive earnings per share calculations for that period as they would be antidilutive.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

	Three Months Ended March 31,
		2016			2015
Basic EPS (in thousands, except per share data)
Numerator:
Basic net loss attributable to Parsley Energy, Inc. Stockholders	$	(19,354	)	$	(17,024	)
Denominator:
Basic weighted average shares outstanding		135,963			101,273
Basic EPS attributable to Parsley Energy, Inc. Stockholders	$	(0.14	)	$	(0.17	)
Diluted EPS
Numerator:
Net loss attributable to Parsley Energy, Inc. Stockholders		(19,354	)		(17,024	)
Effect of conversion of the shares of Company's Class B Common Stock to shares of the Company's Class A Common Stock		-			-
Diluted net loss attributable to Parsley Energy, Inc. Stockholders	$	(19,354	)	$	(17,024	)
Denominator:
Basic weighted average shares outstanding		135,963			101,273
Effect of dilutive securities:
Class B Common Stock		-			-
Restricted Stock and Restricted Stock Units		-			-
Diluted weighted average shares outstanding (1)		135,963			101,273
Diluted EPS attributable to Parsley Energy, Inc. Stockholders	$	(0.14	)	$	(0.17	)

(1)

There were 453,863 and 211,935 shares related to performance-based restricted stock units that could be converted to common shares in the future based on predetermined performance and market goals. These units were not included in the computation of EPS for the three months ended March 31, 2016 and 2015, 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

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

	Three Months Ended March 31,
	2016			2015
	(In thousands)
Net income (loss) attributable to the noncontrolling interests of:
Parsley LLC	$	(6,357	)	$	(6,534	)
Pacesetter Drilling, LLC		20			-
Total net loss attributable to noncontrolling interest	$	(6,337	)	$	(6,534	)

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 9. STOCK-BASED COMPENSATION

In connection with the Company's initial public offering (the "IPO") in May 2014, the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan for employees, consultants, and directors of the Company who perform services for the Company. Refer to "Compensation Discussion and Analysis-Elements of Compensation -2014 Long-Term Incentive Plan" in the Company's Proxy Statement filed on Schedule 14A for the 2016 Annual Meeting of Stockholders for additional information related to this equity based compensation plan.

Performance Units

In February 2016, additional performance-based, stock-settled restricted stock units, which we refer to as performance units, were granted with a performance period of three years. The number of shares of Class A Common Stock actually vesting pursuant to these performance units depends on the performance of the Company's Class A Common Stock over the three-year performance period relative to the performance of the stock of predetermined peer group companies. The Company granted a target number of 241,928 performance units, but the conditions of the grants allow for an actual payout ranging between no payout and 200% of target. The fair value of such performance units was determined using a Monte Carlo simulation and will be recognized over the next three years.

The following table summarized the Company's restricted stock, restricted stock unit, and performance unit activity for the three months ended March 31, 2016 (in thousands):

	Restricted Stock		Restricted Stock Units			Performance Units
Outstanding at January 1, 2016		661		513			212
Awards granted (1)		-		549			242
Vested		-		(4	)		-
Repurchased				1
Outstanding at March 31, 2016		661		1,059			454

(1) Weighted average grant date fair value	$	-	$	16.70		$	25.82

Stock-based compensation expense related to restricted stock, restricted stock units, and performance units was $2.8 million and $1.6 million for the three months ended March 31, 2016 and 2015, respectively. There was approximately $29.3 million of unamortized compensation expense relating to outstanding restricted stock, restricted stock units, and performance units at March 31, 2016.

NOTE 10. INCOME TAXES

The Company is a corporation and it is subject to U.S. federal income tax. The tax implications of the IPO and the Company's concurrent corporate reorganization, and the tax impact of the Company's status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying condensed consolidated financial statements. The effective combined U.S. federal and state income tax rate as of March 31, 2016 was 27.1%. During the three months ended March 31, 2016 and 2015, the Company recognized an income tax benefit of $9.6 million and $5.5 million, respectively. Total income tax expense for the three months ended March 31, 2016 differed from amounts computed by applying the U.S. federal statutory tax rate of 35% due primarily to the impact of loss attributable to noncontrolling ownership interests.

The Company early adopted ASU 2016-09 effective January 1, 2016, which resulted in a favorable adjustment for the net excess income tax benefits from stock-based compensation during the three months ended March 31, 2016. The adoption was on a prospective basis and therefore had no impact on prior years. The Company also recorded an adjustment to opening retained earnings of $0.1 million to recognize U.S. net operating loss carryforwards attributable to excess tax benefits on stock-based compensation that had not been previously recognized to additional paid in capital because they did not reduce income taxes payable.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 11. RELATED PARTY TRANSACTIONS

Well Operations

During the three months ended March 31, 2016 and 2015, several of the Company's directors, officers, 10% stockholders, 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 months ended March 31, 2016 and 2015, totaled $0.8 million and $1.8 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 defined in Note 2-Basis of Presentation , the Company owns a 42.5% interest in SPS. Using the equity method of accounting results in transactions between the Company and SPS and its subsidiaries being accounted for as related party transactions. During the three months ended March 31, 2016 and 2015, the Company incurred charges totaling $1.3 million and $1.8 million, respectively, for services performed by SPS for the Company's well operations and drilling activities.

Lone Star Well Service, LLC

The Company makes purchases of equipment used in its drilling operations from Lone Star Well Service, LLC ("Lone Star"), which is controlled by SPS. During the three months ended March 31, 2016 and 2015, the Company incurred charges totaling $1.1 million and $0.9 million, respectively, for services performed by Lone Star for the Company's wells operations and drilling activities.

Exchange Right

In accordance with the terms of the First Amended and Restated Limited Liability Company Agreement of Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange their PE Units (and a corresponding number of shares of the Company's Class B Common Stock), for shares of the Company's 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 cash (pursuant to the Cash Option). As a PE Unit Holder exchanges its PE Units, the Company's interest in Parsley LLC will be correspondingly increased.

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 holders of PE Units prior to the IPO (each such person a "TRA Holder"), including certain executive officers. This agreement generally provides for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of (i) any tax basis increases resulting from the contribution in connection with the IPO by such TRA Holder of all or a portion of its PE Units to the Company in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange by such TRA Holder of PE Units for shares of Class A Common Stock pursuant to the Exchange Right (or resulting from an exchange of PE Units for cash pursuant to the Cash Option) 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 anticipated future tax benefits subject to the TRA (based upon certain assumptions and deemed events set forth in the TRA). In addition, payments due under the TRA will be similarly accelerated following certain mergers or other changes of control.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 12. SIGNIFICANT CUSTOMERS

For the three months ended March 31, 2016 and 2015, each of the following purchasers accounted for more than 10% of the Company's revenue:

	Three Months Ended March 31,
	2016		2015
Shell Trading (US) Company		38%		10%
BML, Inc.		22%		17%
Targa Pipeline Mid-Continent, LLC		14%		19%
TransOil Marketing, LLC		11%		13%
Permian Marketing, LLC		1%		10%
Sunoco Logistics Partners L.P.		1%		10%

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

NOTE 13. 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 :		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
		Level 2 :		Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company's valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.
		Level 3 :		Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (supported by little or no market activity). The Company's valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

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 in whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. These assets and liabilities can include inventory, proved and unproved oil and natural gas properties, and other long-lived assets that are written down to fair value when they are impaired.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Prov ed oil and natural gas properties. During the three months ended March 31, 2016, reductions in management's long-term commodity price outlooks provided indications of possible impairment. As a result of management's assessments, during the three months end ed March 31, 2016 and 2015, the Company did not recognize impairment charges to reduce the carrying values of any oil and gas properties to their estimated fair values.

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 appropriate risk-adjusted probable and possible reserves and (iv) results of future drilling activities.

Financial Assets and Liabilities Measured at Fair Value

Commodity derivative contracts are marked-to-market each quarter and are thus stated at fair value in the accompanying condensed consolidated Balance Sheets and in Note 3-Derivative Financial Instruments . The fair values of the Company's commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The following summarizes the fair value of the Company's derivative assets and liabilities according to their fair value hierarchy as of the reporting dates indicated (in thousands):

	March 31, 2016
	Level 1		Level 2			Level 3		Total
Commodity derivative contracts
Assets:
Short-term derivative instruments	$	-	$	72,081		$	-	$	72,081
Long-term derivative instruments		-		20,119			-		20,119
Total derivative instrument - asset		-		92,200			-		92,200

Liabilities:
Short-term derivative instruments		-		(30,610	)		-		(30,610	)
Long-term derivative instruments		-		(11,981	)		-		(11,981	)
Total derivative instruments - liability		-		(42,591	)		-		(42,591	)
Net commodity derivative asset	$	-	$	49,609		$	-	$	49,609

	December 31, 2015
	Level 1		Level 2			Level 3		Total
Commodity derivative contracts
Assets:
Short-term derivative instruments	$	-	$	83,262		$	-	$	83,262
Long-term derivative instruments		-		25,839			-		25,839
Total derivative instrument - asset		-		109,101			-		109,101

Liabilities:
Short-term derivative instruments		-		(34,518	)		-		(34,518	)
Long-term derivative instruments		-		(15,142	)		-		(15,142	)
Total derivative instruments - liability		-		(49,660	)		-		(49,660	)
Net commodity derivative asset	$	-	$	59,441		$	-	$	59,441

PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Financial Instruments Not Carried at Fair Value

The estimated fair value of the Company's $550.0 million of Notes at March 31, 2016, was approximately $548.6 million. The fair value of the Notes is classified as a Level 1 measurement as it is calculated based on market quotes.

The book value of the Revolving Credit Agreement approximates its fair value as the interest rate is variable. As of March 31, 2016, there are no indicators for change in the Company's market spread.

The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, prepaid expenses, other current assets, accounts payable and accrued liabilities that approximate their fair value due to the short-term nature of these instruments. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination and asset retirement obligations.

NOTE 14. 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.

Public Offering

On April 4, 2016, the Company entered into an agreement to sell 20,987,500 shares of Class A Common Stock (including 2,737,500 shares issued pursuant to the underwriters' option to purchase additional shares) at a price of $21.40 per share in the April Offering. The April Offering closed on April 8, 2016 and resulted in gross proceeds of approximately $449.1 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $433.1 million. A portion of the net proceeds from the April Offering will be used to fund certain acquisitions announced in April 2016, including the acquisition of oil and gas interests in the Southern Delaware Basin described below. The remaining net proceeds will be used to fund a portion of the Company's capital program and for general corporate purposes, including future acquisitions.

Upon completion of the April Offering, the Company contributed all of the net proceeds to Parsley LLC in exchange for 20,987,500 PE Units. As a result, the Company's ownership of Parsley LLC increased to 83.1%, and the PE Unit Holders' ownership of Parsley LLC decreased to 16.9%.

Southern Delaware Basin Acquisition

In March 2016, the Company entered into a purchase and sale agreement to acquire certain oil and gas interests located in the Southern Delaware Basin for an aggregate purchase price of $136.0 million (subject to customary purchase price adjustments), inclusive of a deposit of $13.6 million paid by the Company upon entering into the purchase and sale agreement. The deposit is included in other current assets on the condensed consolidated balance sheets and as an operating activity on the condensed consolidated statement of cash flows, included herein. The acquisition adds 10,737 gross (9,821 net) surface acres and production from seven horizontal wells and 20 vertical wells. This acquisition closed on May 3, 2016.

Affirmation of Borrowing Base

In April 2016, the bank lending group party to the Revolving Credit Agreement affirmed the Company's Borrowing Base of $575.0 million.

Item 2. Management's Discussion and Analysis o f Financial Condition and Results of Operation

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, 2015 (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. We are a holding company whose sole material asset consists of 157,610,907 PE Units. We are the managing member of Parsley Energy, LLC ("Parsley LLC") and are responsible for all operational, management and administrative decisions of Parsley LLC, and we consolidate the financial results of Parsley LLC and its subsidiaries.

We are an independent oil and natural gas company focused on the acquisition, development and exploitation of unconventional oil and natural gas reserves in the Permian Basin. Our properties are located in the Midland and Delaware Basins and our activities have historically been focused on the vertical development of the Spraberry, Wolfberry and Wolftoka Trends of the Midland Basin. Our vertical wells in the area are drilled into stacked pay zones that include the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline), Strawn, Atoka and Mississippian formations. We now focus predominantly on horizontal development drilling and expect to target various stacked pay intervals in the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline) and Atoka shales.

Our Properties

At March 31, 2016, our acreage position was 136,213 gross (102,726 net) acres, which includes 101,006 gross (73,746 net) acres in the Midland Basin and 35,207 gross (28,980 net) acres in the Delaware Basin. The majority of our identified horizontal drilling locations are located in our horizontal focus area, which is comprised of specific portions of Upton, Reagan, Midland, and Glasscock Counties in Texas. As of March 31, 2016, we operated 599 (389.1 net) vertical wells across our acreage in the Midland Basin. Since commencing our horizontal drilling program in 2013 through March 31, 2016, we have drilled and completed 82 gross (73.7 net) horizontal wells in the Midland Basin, of which 15 gross (14.8 net) were completed during the three months ended March 31, 2016. We have also drilled and completed one gross (0.9 net) horizontal wells in the Delaware Basin. As of March 31, 2016, we operated 88 gross (78.2 net) horizontal wells. As of March 31, 2016, we had drilled and completed three vertical appraisal wells and one horizontal appraisal well in the Delaware Basin. As of December 31, 2015, we have identified 2,677 potential horizontal drilling locations and 147 80- and 40-acre potential vertical drilling locations on our existing acreage, which does not include any locations in our Southern Delaware Basin acreage. As of March 31, 2016, we had interests in 713 gross (469.8 net) producing wells across our properties and operated 99.5% of the wells in which we had an interest.

How We Evaluate Our Operations

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

●

production volumes;

●

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

●

lease operating expenses;

●

capital expenditures;

●

completions activities; and

●

certain unit costs.

Sources of Our Revenues

Our 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. Our oil, natural gas, and NGLs revenues do not include the effects of derivatives. For the three months ended March 31, 2016 and 2015, our revenues were derived 84% and 79%, respectively, from oil sales; 9% and 13%, respectively, from natural gas sales; and 7% and 8%, respectively, from NGLs sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Production Volumes

The following table presents historical production volumes for our properties for the three months ended March 31, 2016 and 2015.

	Three Months Ended March 31,
	2016		2015
Oil (MBbls)		1,731		1,009
Natural gas (MMcf)		2,944		2,302
Natural gas liquids (MBoe)		425		310
Total (MBoe)		2,647		1,703
Average net production (Boe/d)		29,088		18,919

Production Volumes Directly Impact Our Results of Operations

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

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

Historically, oil, natural gas, and NGLs prices have been extremely volatile, and we expect this volatility to continue. Since our production consists primarily of oil, our revenues are more sensitive to price fluctuations in the price of oil than they are to fluctuations in NGLs or natural gas prices. During the three months ended March 31, 2016, WTI posted prices ranged from $26.21 to $41.45 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.64 to $2.47 per MMBtu. During the three months ended March 31, 2015, WTI posted prices ranged from $43.46 to $53.53 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.58 to $3.23 per MMBtu.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for 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. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our derivatives contract prices are higher than market prices. See "Item 3. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk" for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

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

Our positions hedging production as of March 31, 2016 were as follows:

Description and Production Period	VOLUME (Bbls)		SHORT PUT PRICE ($/Bbl)		LONG PUT PRICE ($/Bbl)		DIFFERENTIAL PRICE
Crude Oil Put Spreads:
Apr 2016 - Jun 2016		150,000	$	35.00	$	60.00
Apr 2016 - Dec 2016		750,000	$	35.00	$	50.00
Apr 2016 - Jun 2016		525,000	$	30.00	$	40.00
Apr 2016 - Jun 2016		960,000	$	30.00	$	40.00
Jun 2016 - Dec 2016		525,000	$	35.00	$	50.00
Jul 2016 - Sept 2016		75,000	$	40.00	$	55.00
Jul 2016 - Dec 2016		2,460,000	$	40.00	$	55.00
Aug 2016 - Dec 2016		250,000	$	35.00	$	50.00
Oct 2016 - Dec 2016		180,000	$	40.00	$	55.00
Jan 2017 - Jun 2017		900,000	$	40.00	$	55.00
Jan 2017 - Jun 2017		3,234,000	$	37.50	$	52.50

Crude Oil Basis Swaps:
Jul 2016 - Dec 2016		210,000					$	(1.40	)
Jul 2016 - Dec 2016		180,000					$	(1.35	)
Jul 2016 - Dec 2016		368,000					$	(0.35	)
Jul 2016 - Dec 2016		390,000					$	(1.40	)
Jul 2016 - Dec 2016		368,000					$	(0.30	)
Jan 2017 - Dec 2017		600,000					$	(1.70	)
Jan 2017 - Dec 2017		360,000					$	(1.60	)
Jan 2017 - Dec 2017		960,000					$	(1.65	)
Jan 2017 - Dec 2017		1,095,000					$	(0.40	)
Jan 2017 - Dec 2017		1,095,000					$	(0.45	)
Jul 2017 - Dec 2017		180,000					$	(1.65	)

We will recognize the following income (expense) in the line item Derivative income (loss) on our condensed consolidated statements of operations from net cash premiums (paid) received on options that settled during the following periods:

Q2 2016	$	10,552
Q3 2016	$	(2,754	)
Q4 2016	$	(2,982	)
Q1 2017	$	(5,476	)
Q2 2017	$	(5,476	)
Q3 2017	$	(1,238	)
Q4 2017	$	(1,238	)

Impairment of Oil and Gas Properties

Proved oil and 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 gas properties and compare the undiscounted cash flows to the carrying amount of the oil and 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 gas properties to estimated fair value.

As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and natural gas properties for impairment. During the periods ended March 31, 2016 and 2015, we did not recognize an impairment of our proved oil and gas properties. At March 31, 2016, in our significant fields that comprise 99% of our carrying value, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by an average of 106% and individually a minimum of 20%.

The key assumptions used to determine the un discounted future cash flows include, but are not limited to, future commodity prices, based on five-year WTI futures price index for oil and NGLs and five-year Henry Hub futures price index for natural gas, price differentials, future production estimates , estimated future capital expenditures and estimated future operating expenses. All inputs remained relatively consistent in the undiscounted future cash flow estimate from December 31, 2015 to March 31, 2016 except commodity price estimates. Future commo dity pricing for oil and NGLs is based on five-year WTI futures prices, which decreased 4% from December 31, 2015 to March 31, 2016, and on five-year Henry Hub futures prices, which decreased 2% from December 31, 2015 to March 31, 2016. In terms of the red uction in value of undiscounted cash flows from December 31, 2015 to March 31, 2016, the effect of the decrease in pricing has been mitigated to a certain extent 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 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, which we expect to decrease further in the near term as a result of sustained lower commodity prices. There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in "Item 1A. Risk Factors" included in our Annual Report.

Any decrease in pricing, negative change in price differentials, increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties. A decrease of 10% in estimated future pricing of oil and natural gas commodities as of March 31, 2016 would have resulted in an estimated impairment of proved oil and gas properties of $43.6 million.

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

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

Recent Transactions

Public Offering of Common Stock

On April 4, 2016, we entered into an agreement to sell 20,987,500 shares of Class A Common Stock (including 2,737,500 shares issued pursuant to the underwriters' option to purchase additional shares) at a price of $21.40 per share in an underwritten public offering (the "April Offering"). The April Offering closed on April 8, 2016 and resulted in gross proceeds of approximately $449.1 million to us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $433.1 million. A portion of the net proceeds from the April Offering will be used to fund the acquisition of oil and gas interests in the Southern Delaware and Midland Basins, as described below. The remaining net proceeds will be used to fund a portion of our capital program and for general corporate purposes, including future acquisitions.

Upon completion of the April Offering, we contributed all of the net proceeds to Parsley LLC in exchange for 20,987,500 PE Units. As a result, our ownership of Parsley LLC increased to 83.1%, and the PE Unit Holders' ownership of Parsley LLC decreased to 16.9%.

Acquisitions of Oil and Gas Properties

On April 4, 2016, we announced that we had entered into separate, individually-negotiated agreements to acquire certain oil and gas interests located in the Southern Delaware and Midland Basins for an aggregate purchase price of $359.3 million (subject to customary purchase price adjustments). During the quarter ended March 31, 2016, we paid $47.8 million and a deposit of $13.6 million related to the acquisitions described below.

Southern Delaware Basin Acquisitions . The acquisitions announced on April 4, 2016 include the acquisition of 19,324 gross (14,197 net) acres in Reeves and Ward Counties, Texas for an aggregate purchase price of $144.2 million (subject to customary purchase price adjustments). This total is primarily comprised of one acquisition. On March 11, 2016, we entered into a purchase and sale agreement with undisclosed third parties (collectively, the "Delaware Basin Sellers") that prov ides for the sale and transfer by the Delaware Basin Sellers of their interests in 10,737 gross (9,821 net) acres located in Reeves and Ward Counties, Texas (the "Delaware Basin Acquisition"), for an aggregate purchase price of $136.0 million in cash (subject to customary purchase price adjustments). At the time of signing, the properties to be acquired had an estimated current net production of approximately 1,200 Boe/d from seven horizontal and 20 vertical producing wells.

In connection with the Delaware Basin Acquisition, we paid a deposit in March 2016 equal to $13.6 million to the Delaware Basin Sellers. This deposit is included in other current assets on the condensed consolidated balance sheet for the year ended March 31, 2016 and as an operating activity on the condensed consolidated statement of cash flows for the three months ended March 31, 2016, included herein. As discussed in Note 14-Subsequent Events to our condensed consolidated financial statements included elsewhere in this Quarterly Report, on May 3, 2016, the Delaware Basin Acquisition closed and we paid the balance of the purchase price ( i.e. , $136.0 million less the $13.6 million deposit previously paid and including certain customary purchase price adjustments) to the Delaware Basin Sellers.

Midland Basin Acquisitions . The acquisitions announced on April 4, 2016 include the acquisition of 11,844 gross (8,711 net) acres in Midland, Upton, Reagan, and Glasscock Counties, Texas for an aggregate purchase price of $215.1 million. The $215.1 million total includes an acquisition of certain oil and gas interests from Riverbend Permian, L.L.C. ("Riverbend"). On April 1, 2016, we entered into a purchase and sale agreement (the "Riverbend Purchase Agreement") with Riverbend. The Riverbend Purchase Agreement provides for the sale and transfer by Riverbend of its interests in 8,800 gross (6,269 net) acres located in Glasscock, Midland and Reagan Counties, Texas (the "Riverbend Acquisition") for an aggregate purchase price of $175.5 million in cash (subject to customary purchase price adjustments). At the time of signing, the properties to be acquired had an estimated current net production of approximately 900 Boe/d from two horizontal and 37 vertical producing wells.

Randolph J. Newcomer, Jr., a member of our board of directors, is the President and Chief Executive Officer of Riverbend. As the transaction involves a related party, the Riverbend Acquisition was approved by the disinterested members of our board of directors. We and Riverbend expect to close the Riverbend Acquisition on or before May 16, 2016, subject to the satisfaction of customary closing conditions, including the receipt of an opinion from an independent valuation firm with respect to the fairness of the Riverbend Acquisition.

Stock-Based Compensation

Stock-based compensation includes amortization expense related to grants from our 2014 Long Term Incentive Plan. Refer to Note 9-Stock-Based Compensation to our condensed consolidated financial statements included elsewhere in this Quarterly Report for additional discussion.

Drilling Activity

As of March 31, 2016, we operated four horizontal drilling rigs on our properties. For the three months ended March 31, 2016, our capital expenditures for drilling and completions were $110.4 million, as compared to $400.9 million for all of fiscal year ended December 31, 2015.

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 interest owners.

Results of Operations

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

Oil and Natural Gas Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period's respective average prices and production volumes:

	Three Months Ended March 31,
	2016		2015		Change			% Change
Revenues (in thousands, except percentages):
Oil sales	$	52,031	$	43,688	$	8,343			19	%
Natural gas sales		5,543		6,956		(1,413	)		(20	)%
Natural gas liquids sales		4,694		4,567		127			3	%
Total revenues	$	62,268	$	55,211	$	7,057			13	%

Average realized prices (1) :
Oil sales, without realized derivatives (per Bbls)	$	30.06	$	43.30	$	(13.24	)		(31	)%
Oil sales, with realized derivatives (per Bbls)		46.73		55.71		(8.98	)		(16	)%
Natural gas, without realized derivatives (per Mcf)		1.88		3.02		(1.14	)		(38	)%
Natural gas, with realized derivatives (per Mcf)		1.88		3.22		(1.33	)		(41	)%
NGLs sales (per Boe)		11.04		14.73		(3.69	)		(25	)%
Average price per Boe, without realized derivatives		23.52		32.42		(8.90	)		(27	)%
Average price per Boe, with realized derivatives		34.42		40.04		(5.61	)		(14	)%

Production:
Oil (MBbls)		1,731		1,009		722			72	%
Natural gas (MMcf)		2,944		2,302		642			28	%
Natural gas liquids (MBoe)		425		310		115			37	%
Total (MBoe)		2,647		1,703		944			55	%

Average daily production volume:
Oil (Bbls)		19,022		11,211		7,811			70	%
Natural gas (Mcf)		32,352		25,578		6,774			26	%
Natural gas liquids (Boe)		4,670		3,444		1,226			36	%
Total (Boe/d)		29,088		18,919		10,169			54	%

(1)

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

The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationshi p between our average realized natural gas price as a percentage of the average NYMEX price for the years indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

	Three Months Ended March 31,
	2016			2015
Average realized oil price ($/Bbl)	$	30.06		$	43.30
Average NYMEX ($/Bbl)	$	33.83		$	48.50
Differential to NYMEX	$	(3.77	)	$	(5.20	)
Average realized oil price to NYMEX percentage		89	%		89	%
Average realized natural gas price ($/Mcf)	$	1.88		$	3.02
Average NYMEX ($/Mcf)	$	2.06		$	2.91
Differential to NYMEX	$	(0.18	)	$	0.11
Average realized natural gas to NYMEX percentage		91	%		104	%
Average realized NGLs price ($/Boe)	$	11.04		$	14.73
Average NYMEX ($/Boe)	$	33.83		$	48.50
Differential to NYMEX	$	(22.79	)	$	(33.77	)
Average realized NGLs price to NYMEX oil percentage		33	%		30	%

Oil revenues increased 19% to $52.0 million during the three months ended March 31, 2016 from $43.7 million during the three months ended March 31, 2015. The increase is attributable to an increase in oil production volumes of 722 MBbls offset by a $13.24 per barrel decrease in average oil prices. Of the overall changes in oil revenues, the increase in oil production volumes accounted for a positive change of $31.3 million, offset by the decrease in oil prices, which accounted for a negative change of $23.0 million.

Natural gas revenues decreased 20% to $5.5 million during the three months ended March 31, 2016 from $7.0 million during the three months ended March 31, 2015. The decrease is attributable to a $1.14 per Mcf decrease in average natural gas prices, offset by an increase in volumes sold of 642 MMcf. Of the overall changes in natural gas revenues, the decrease in price accounted for a negative change of $3.3 million, offset by increases in natural gas production volumes, which accounted for a positive change of $1.9 million.

NGLs revenues increased by 3% to $4.7 million during the three months ended March 31, 2016 from $4.6 million during the three months ended March 31, 2015. The increase is attributable to a 115 MBoe increase in NGLs production offset by a $3.69 per Boe decrease in average NGLs price. Of the overall changes in NGLs revenues, the increase in production volumes accounted for a positive change of $1.7 million and the increase in NGLs average price accounted for a negative change of $1.6 million.

Operating Expenses. The f ollowing table summarizes our expenses for the periods indicated:

	Three Months Ended March 31,
	2016		2015		$ Change			% Change
Operating expenses (in thousands, except percentages) :
Lease operating expenses	$	13,898	$	16,398	$	(2,500	)		(15	)%
Production and ad valorem taxes		4,195		4,495		(300	)		(7	)%
Depreciation, depletion and amortization		49,384		37,381		12,003			32	%
General and administrative expenses (1)		19,299		12,981		6,318			49	%
Exploration costs		688		3,219		(2,531	)		(79	)%
Accretion of asset retirement obligations		170		249		(79	)		(32	)%
Rig termination costs		-		5,100		(5,100	)	*
Other operating expenses		896		-		896		*
Total operating expenses	$	88,530	$	79,823	$	8,707			11	%

Expense per Boe:
Lease operating expenses	$	5.25	$	9.63	$	(4.38	)		(45	)%
Production and ad valorem taxes		1.58		2.64		(1.06	)		(40	)%
Depreciation, depletion and amortization		18.66		21.95		(3.29	)		(15	)%
General and administrative expenses (1)		7.29		7.62		(0.33	)		(4	)%
Exploration costs		0.26		1.89		(1.63	)		(86	)%
Accretion of asset retirement obligations		0.06		0.15		(0.09	)		(60	)%
Rig termination costs		-		2.99		(2.99	)	*
Other operating expenses		0.34		-		0.34		*
Total operating expenses per Boe	$	33.44	$	46.87	$	(13.43	)		(29	)%

(1)	General and administrative expenses include stock-based compensation expense of $2.8 million and $1.6 million for the three months ended March 31, 2016 and 2015, respectively.

*	The percentage change is not considered meaningful.

Lease Operating Expenses. Lease operating expenses decreased 15% to $13.9 million during the three months ended March 31, 2016 from $16.4 million during the three months ended March 31, 2015. The decrease is primarily due to a greater portion of our production coming from horizontal wells in our Midland Basin core area which has lower per Boe lease operating costs as well as the cost reduction initiatives implemented by management. On a per Boe basis, lease operating expenses decreased to $5.25 per Boe during the three months ended March 31, 2016 from $9.63 per Boe during the three months ended March 31, 2015. Additionally, the decrease in lease operating expenses per Boe year-over-year is partially attributable to a 55% increase in production during the same period.

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased 7% to $4.2 million during the three months ended March 31, 2016 from $4.5 million during the three months ended March 31, 2015. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior period commodity prices, whereas production taxes are based on current period commodity prices. Overall, ad valorem taxes decreased by approximately $0.6 million, reflecting lower property assessments due to lower commodity prices, which is offset by a $0.3 million increase in production taxes due to increased production volumes.

Depreciation, Depletion and Amortization . DD&A expense increased $12.0 million, or 32%, to $49.4 million for the three months ended March 31, 2016 from $37.4 million for the three months ended March 31, 2015. The increase is attributable to a $287.7 million increase in costs subject to depletion and a 55% increase in production, which is offset by a 51% increase in total proved reserves and a 41% increase in proved developed reserves. On a per Boe basis, DD&A decreased $3.29 per Boe, or 15%, to $18.66 for the three months ended March 31, 2016 from $21.95 per Boe during the three months ended March 31, 2015 primarily due to the increase in production volumes, which is offset by the increase in reserves, as discussed above.

General and Administrative Expenses. General and administrative expenses increased 49% to $19.3 million during the three months ended March 31, 2016 from $13.0 million during the three months ended March 31, 2015 primarily due to higher payroll and s tock-based compensation expenses associated with the hiring of additional employees to manage our growing asset base and increased production. In addition, we incurred increased rent expense for our new corporate headquarters as well as increased professio nal fees and consultant costs associated with ongoing public company operations. On a per Boe basis, general and administrative expenses decreased $0.33 per Boe, or 4%, to $7.29 per Boe for the three months ended March 31, 2016 from $7.62 per Boe for the t hree months ended March 31, 2015.

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

	Three Months Ended March 31,
	2016		2015
Idle drilling rig fees	$	599	$	-
Unproved leasehold amortization		82		19
Geological and geophysical costs		7		1,504
Leasehold abandonments		-		1,696
Total exploration costs	$	688	$	3,219

Exploration costs include idle drilling rig fees of $0.6 million that are not chargeable to our joint operations during the three months ended March 31, 2016. Such fees are expected to ratably continue until the expiration of the drilling rig contract in March 2017. There were no such expenses incurred during the three months ended March 31, 2015.

Our geological and geophysical ("G&G") expenses consist of the costs of acquiring and processing seismic data, geophysical data and core analysis, primarily relating to increased geoscientific analysis of our Delaware Basin assets. During the three months ended March 31, 2015, we acquired G&G data related to our Delaware Basin acreage.

We recognized leasehold amortization expense during the three months ended March 31, 2016 and 2015, which relates to amortization of unproved leasehold costs. We recognized leasehold abandonment expenses of approximately $1.7 million during the three months ended March 31, 2015, which primarily relates to expired acreage and expiring acreage determined to be outside of our economically productive reserves. There were no such expenses incurred during the three months ended March 31, 2016.

Rig Termination. During the three months ended March 31, 2015, we paid a total of $5.1 million in rig termination expenses, which is comprised of approximately $4.1 million related to the termination of drilling rig contracts entered into in 2014 and approximately $1.0 million for stacking fees associated with certain drilling rig contracts. There were no such expenses incurred during the three months ended March 31, 2016.

Other Operating Expenses. During the three months ended March 31, 2016, other operating expenses were approximately $0.9 million, which is related to operating expenses incurred during the normal course of business by our majority-owned subsidiary, Pacesetter Drilling, LLC. There were no such expenses incurred during the three months ended March 31, 2015.

Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:

	Three Months Ended March 31,
	2016			2015			$ Change			% Change
Other income (expense) (in thousands, except percentages):
Interest expense, net	$	(11,289	)	$	(11,841	)	$	552			(5	)%
Gain on sale of property		350			-			350		*
Derivative income		2,088			7,142			(5,054	)		(71	)%
Other income (expense)		(146	)		279			(425	)	*
Total other income (expense), net	$	(8,997	)	$	(4,420	)	$	(4,577	)	*

*	The percentage change is not considered meaningful.

Interest Expense, Net . Interest expense decreased 5% to $11.3 million during the three months ended March 31, 2016 from $11.8 million during the three months ended March 31, 2015 primarily due to a decrease in weighted average debt outstanding. During the three months ended March 31, 2016, we had no borrowings under our amended and restated credit agreement with Wells Fargo Bank, National Asso ciation, as administrative agent (as amended, the "Revolving Credit Agreement") . During the three months ended March 31, 2015, the Revolving Credit Agreement had an outstanding balance of $120.0 million through February 11, 2015 resulting in weighted avera ge outstanding balance of $55.3 million.

Derivative Income. Derivative income decreased 71% to a gain of $2.1 million during the three months ended March 31, 2016, as compared to $7.1 million during the three months ended March 31, 2015, primarily as a result of the unfavorable commodity price changes for operations, which is offset by increased hedging activities.

Other Income (Expense). Other income (expense) decreased 152%, or $0.4 million, to an expense of $0.1 million during the three months ended March 31, 2016 as compared to income of $0.3 million during the three months ended March 31, 2015. The decrease is attributable to a $0.4 million decrease in our equity investment income.

Income Tax Benefit

The effective combined U.S. federal and state income tax rate as of March 31, 2016 was 27.1%. During the three months ended March 31, 2016, we recognized a tax benefit of $9.6 million, an increase of $4.1 million, or 75% as compared to the $5.5 million tax benefit we recognized during the three months ended March 31, 2015. This increase was attributable to the corresponding increase in net losses during the applicable periods, as discussed above.

Capital Requirements and Sources of Liquidity

For the three months ended March 31, 2016, our aggregate drilling and completion capital expenditures were $110.4 million. During the year ended December 31, 2015, our aggregate drilling and completion capital expenditures were $400.9 million. These capital expenditure totals exclude acquisitions.

Our 2016 capital budget for drilling and completion is approximately $410 million to $460 million, including approximately $355 million to $395 million for drilling and completion. Our capital budget excludes any amounts that may be paid for acquisitions. The amount and timing of 2016 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2016 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners.

Based upon our current oil and natural gas price expectations for the remainder of the 2016 fiscal year, we believe that our cash on hand, cash flow from operations, and borrowings under our Revolving Credit Agreement will be sufficient to fund our operations through 2016. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures required to more fully develop our properties. As of March 31, 2016, pro forma for the acquisitions and April Offering described in Recent Transactions , our liquidity is as follows (in thousands):

Cash and cash equivalents	$	28,310
Cash paid for acquisitions		(297,900	)
Cash received for April Offering		433,133
Revolving Credit Agreement availability		574,750
Pro Forma Liquidity	$	738,293

Future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be 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, 2015 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 2016 does not allocate any amounts for acquisitions of leasehold interests and proved 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 and 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 requir ements, contractual restrictions and other factors. The amounts involved may be material.

Cash Flows

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

	Three Months Ended March 31,
	2016			2015
Net cash provided by operating activities	$	19,905		$	17,987
Net cash used in investing activities		(334,459	)		(145,144	)
Net cash (used in) provided by financing activities		(220	)		103,843

Cash Flows from Operating Activities. Net cash provided by operating activities was approximately $19.9 million and $18.0 million for the three months ended March 31, 2016 and 2015, respectively. Net cash provided by operating activities increased from the period ending March 31, 2015 to March 31, 2016 primarily due to a $1.8 million, or 5%, decrease in our cash based operating expenses, which include lease operating expenses, production and ad valorem taxes, certain general and administrative expenses, and exploration costs. Cash provided by operating activities is also impacted by the prices received for oil and natural gas sales and levels of production volumes.

Cash Flows from Investing Activities. Net cash used in investing activities was approximately $334.5 million and $145.1 million for the three months ended March 31, 2016 and 2015, respectively. The increased amount of cash used in investing activities was due primarily to the $187.1 million increase in acquisition costs during the three months ended March 31, 2016 over the three months ended March 31, 2015. Please refer to Note 5-Acquisitions of Oil and Gas Properties to our condensed consolidated financial statements included elsewhere in this Quarterly Report for additional discussion related to acquisitions.

Cash Flows from Financing Activities. Net cash used in financing activities was $0.2 million and net cash provided by financing activities was $103.8 million for the three months ended March 31, 2016 and 2015, respectively. Net cash from financing activities decreased in the period ending March 31, 2016 primarily due to less debt and equity related activity. During the three months ended March 31, 2015, we received proceeds of $224.0 million from a public equity offering, which was offset by long term debt payments of $120.2 million.

Capital Sources

Revolving Credit Agreement. See Note 7-Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report for a description of the Revolving Credit Agreement.

7.500 % Senior Unsecured Notes due 2022. See Note 7-Debt to our condensed consolidated financial statements included elsewhere in this Quarterly Report for a description of the Company's 7.500% senior notes due 2022 (the "Notes").

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

Working Capital

Our working capital totaled ($42.5) million and $259.8 million at March 31, 2016 and December 31, 2015, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $28.3 million and $343.1 million at March 31, 2016 and December 31, 2015, respectively. The $314.8 million decrease in cash is primarily attributable to the acquisitions described in Note 5-Acquisitions of Oil and Natural Gas Properties to our condensed consolidated financial statements included elsewhere in this Quarterly Report as well as the increase in operating expenses in conjunction with the slight decrease in revenues, which is largely attributable to the $8.98 decrease in average oil price including the effects of derivatives. 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 be the largest variables affecting our working capital.

Critical Accounting Policies and Estimates

There have not been any material changes during the three months ended March 31, 2016, to the methodology applied by management for critical accounting policies previously disclosed in our Annual Report, except as described below. Please read "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates" in our Annual Report for further description of the Company's critical accounting policies.

The Company adopted Accounting Standards Update ("ASU") 2015-03, Interest - Imputation of Interest (Subtopic 935-30): Simplifying the Presentation of Debt Issuance Costs , effective January 1, 2016. This standard requires companies that have historically presented debt issuance costs as an asset to present those costs as a direct deduction from the carrying amount of the underlying debt liability. To the extent that there are no borrowings under the Revolving Credit Agreement, the related deferred loan costs will continue to be classified as an asset. The guidance required retrospective application in the condensed consolidated financial statements. The Company had no borrowings outstanding under the Revolving Credit Agreement at March 31, 2016 and December 31, 2015, as such, approximately $2.1 million and $2.3 million, respectively, of deferred loan costs related to the Revolving Credit Agreement are included in "Other noncurrent assets." The Company's Notes are presented net of approximately $8.7 million and $9.1 million of deferred loan costs at March 31, 2016 and December 31, 2015, respectively.

Off-Balance Sheet Arrangements

As of March 31, 2016, we had no material off-balance sheet arrangements.

Item 3. Quantitative and Qualitat ive 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 oil prices. 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 production. Pricing for oil has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

To reduce the impact of fluctuations in oil prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure to oil price fluctuations. For a description of our open positions at March 31, 2016, see Note 3-Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this Quarterly Report.

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

As of March 31, 2016, the fair market value of our oil derivative contracts was a net asset of $49.6 million. Based on our open oil derivative positions at March 31, 2016, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $15.3 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $18.3 million. Please read "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations-Overview-Realized Prices on the Sale of Oil, Natural Gas, and NGLs."

Counterparty Risk

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

Interest Rate Risk

Our market risk exposure related to changes in interest rates relates primarily to debt obligations. We are exposed to changes in interest rates as a result of our Revolving Credit Agreement, and the terms of our Revolving Credit Agreement require us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. As of March 31, 2016, however, we had no outstanding borrowings related to our 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 our Revolving Credit Agreement.

Item 4. C ontrols and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) under the Exchange Act) as of March 31, 2016. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2016, at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the three months ended March 31, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Item 6. Exhibits

The exhibits required to be filed by Item 6 are set forth in the Exhibit Index accompanying this Quarterly Report.

SIGNATURES

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


	PARSLEY ENERGY, INC.

May 6, 2016	By:	/s/ Bryan Sheffield
		Bryan Sheffield
		Chairman, President and Chief Executive Officer Principal Executive Officer


May 6, 2016	By:	/s/ Ryan Dalton
		Ryan Dalton
		Vice President-Chief Financial Officer Principal Accounting and Financial Officer

EXHIBIT INDEX


Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
3.2		Amended and Restated Bylaws of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
10.1 †		Indemnification Agreement, dated as of January 1, 2016, by and between Parsley Energy, Inc. and Cecilia Camarillo (incorporated by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on February 29, 2016).
10.2 †		Indemnification Agreement, dated as of March 23, 2016, by and between Parsley Energy, Inc. and Ronald Brokmeyer (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 March 23, 2016).
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.