UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended June 30, 2015

or

For the transition period from             to             

Commission File Number: 001-36463            

 

PARSLEY ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

(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.

 

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

As of August 13, 2015, the registrant had 108,775,087 shares of Class A common stock and 32,145,296 shares of Class B common stock outstanding.

 

 

 

 

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PARSLEY ENERGY, INC.

FORM 10-Q

QUARTERLY PERIOD ENDED JUNE 30, 2015

 

TABLE OF CONTENTS 

 

 

 

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (the “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements.  When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.  These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.  When considering forward-looking statements, you should 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, 2014 (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:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas, and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in our Annual Report.  

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Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.  If significant, such revisions would change the schedule of any further production and development drilling.  Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.  

Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.  

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

 

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GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

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

“Bbl.” One stock tank barrel, of 42 United States gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.

“Boe.” One barrel of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

“Boe/d.” One barrel of oil equivalent per day.

“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.

“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.

“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.

“development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“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.

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

“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.

“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.

“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).

“formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

“GAAP.” Accounting principles generally accepted in the United States.

“gross acres” or “gross wells.” The total acres or wells, as the case may be, in which an entity owns a working interest.

“horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“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.

“LIBOR.” London Interbank Offered Rate.

“MBbl.” One thousand barrels of crude oil, condensate or NGLs.

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“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.

“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.

“NYMEX.” The New York Mercantile Exchange.

“operator.” The entity responsible for the exploration, development and production of a well or lease.

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

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“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.

“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).

“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.

“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).

“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.

“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.

“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.

“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.

“SEC.” The United States Securities and Exchange Commission.

“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.

“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.

“we,” “our,” “us” or like terms refer to Parsley Energy, Inc., either individually or together with its subsidiaries, as the context requires..  

“wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

“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.

“workover.” Operations on a producing well to restore or increase production.

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

 

 

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PART 1: FINANCIAL INFORMATION

Item 1:    Financial Statements

PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS

(Unaudited)

 

 

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

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

 

 

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

 

 

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

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(Unaudited)

 

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

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(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, as a wholly-owned subsidiary of Parsley Energy, LLC (“Parsley LLC”), a Delaware limited liability company formed on June 11, 2013 and is engaged in the acquisition, development, production, exploration and sale of crude oil and natural gas properties located primarily in the Permian Basin, which is located in West Texas and Southeastern New Mexico.

Initial Public Offering

 

On May 29, 2014, the Company completed its initial public offering (the “Offering”) of 57.5 million shares of the Company’s Class A common stock, par value $0.01 per share (“Class A Common Stock”) at a price of $18.50 per share.  Approximately 7.5 million of the shares were sold by selling stockholders and the Company did not receive any proceeds from the sale of those shares.  The remaining approximately 50 million shares of the Company’s Class A Common Stock that were sold resulted in gross proceeds of approximately $924.3 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $867.8 million.

Corporate Reorganization

 

On May 29, 2014, in connection with the Offering, Parsley LLC underwent a corporate reorganization (“Corporate Reorganization”) whereby (a) all of the membership interests (including outstanding incentive units) in Parsley LLC held by its then existing owners (the “Existing Owners”) were converted into a single class of units in Parsley LLC (PE Units), (b) certain of the Existing Owners contributed all of their PE Units to the Company in exchange for an equal number of shares of the Company’s Class A Common Stock, (c) certain of the Existing Owners contributed only a portion of their PE Units to the Company in exchange for an equal number of shares of the Company’s Class A Common Stock and continue to own a portion of the PE Units and (d) Parsley Energy Employee Holdings, LLC (“PEEH”), an entity owned by certain of Parsley LLC’s officers and employees that was formed to hold a portion of the incentive units in Parsley LLC, was merged with and into the Company, with the Company surviving the merger and the members of PEEH receiving shares of the Company’s Class A Common Stock.  As a result of the above transactions, the Company issued a total of 43.2 million shares of its Class A Common Stock.

Upon completion of the Offering, the Company issued and contributed 32.1 million shares of its Class B common stock, par value $0.01 per share (“Class B Common Stock”) and all of the net proceeds of the Offering to Parsley LLC in exchange for 93.2 million PE Units.  Parsley LLC distributed to each of the Existing Owners that continued to own PE Units following the Corporate Reorganization and the Offering (collectively, the “PE Unit Holders”), one share of Class B Common Stock for each PE Unit such PE Unit Holder held.  

Private Placement of Common Stock

On February 5, 2015, the Company entered into an agreement to sell 14.9 million shares of its Class A Common Stock in a private placement (the “Private Placement”) at a price of $15.50 per share to selected institutional investors.  The Private Placement closed on February 11, 2015, and resulted in gross proceeds of approximately $230.7 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $224.0 million.

Upon completion of the Private Placement, the Company contributed all of the net proceeds of the Private Placement to Parsley LLC in exchange for 14.9 million PE Units.  As a result, the Company’s ownership of Parsley LLC increased to 77.2%, with the PE Unit Holders’ ownership of Parsley LLC decreasing to 22.8%.

Pacesetter Drilling, LLC

On April 21, 2015 Parsley Operations, LLC (“Operations”), established a limited liability company, Pacesetter Drilling, LLC (“Pacesetter”), as a wholly owned subsidiary.  On June 15, 2015, Pacesetter entered into an Asset Purchase Agreement (the “Agreement”) with an oilfield drilling company to acquire certain property, equipment, and other assets (the “Pacesetter

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

Acquisition.”)  The Pacesetter Acquisition was accounted for using the acquisition method under Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations.”  Pacesetter paid total consideration of $7.0 million for its interest in the purchased assets, which consists of $4.4 million of cash consideration (including $2.0 million of cash and cash equivalents acquired), and a noncontrolling interest in Pacesetter valued at approximately $2.6 million.  As a result of the Pacesetter Acquisition, Operations has a 63.0% interest in Pacesetter.

NOTE 2.    BASIS OF PRESENTATION

These condensed consolidated and combined financial statements include the accounts of the Company and its majority-owned subsidiary, Parsley LLC, and its wholly-owned subsidiaries: (i) Parsley Energy, L.P. (“Parsley LP”), (ii) Parsley Energy Management, LLC (the “General Partner”), (iii)  Operations, and its wholly-owned subsidiary, Parsley Energy Aviation, LLC, and (iv) Parsley Finance Corp (“Finance Corp”).  These condensed consolidated and combined financial statements also include the accounts of Pacesetter, Operations’ majority-owned subsidiary. 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 and combined financial statements should be read in conjunction with Parsley LLC’s audited condensed consolidated and combined 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 and six month periods ending June 30, 2015, is not necessarily indicative of the operating results of the entire fiscal year ending December 31, 2015.

Use of Estimates

These condensed consolidated and combined 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 and combined financial statements are the following:

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

Significant Accounting Policies

For a complete description of the Company’s significant accounting policies, see Note 3—Summary of Significant Accounting Policies in the Annual Report.

Revenues

During the three and six months ended June 30, 2015, our NGLs are reported separately as adequate historical information was available to conform to comparative presentation.  During prior periods, NGLs were reported combined with natural gas.

Materials and Supplies

Materials and supplies are stated at the lower of cost or market and consists of oil and gas drilling or repair items such a tubing, casing and pumping units.  These items are primarily acquired for use in future drilling or repair operations and are carried at lower of cost or market.  “Market,” in the context of valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint account under joint operating agreements to which the Company is a party.  During the second quarter of 2015, the Company made significant materials and supplies purchases and evaluated assets based on current operations.  The Company determined that these materials and supplies would not be utilized in the current year and therefore reclassified them to noncurrent assets as non-depreciable other property, plant and equipment.

Reclassifications

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

Recent Accounting Pronouncements

On May 28, 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, 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. The ASU 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, 2017. 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 will have on its consolidated and combined 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 February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which changes the analysis to be performed in determining whether certain types of legal entities should be consolidated.  Under the revised guidance, all legal entities are subject to reevaluation under the revised consolidation model, unless a scope exception applies.  Though the revised guidance mostly affects asset managers, all reporting entities involved with limited partnerships or similar entities are required to reevaluate such entities for consolidation.  The guidance is effective for public business entities for fiscal years and for interim periods within those fiscal years beginning after December 15, 2015.  The amended guidance will not materially affect the Company’s condensed consolidated and combined financial statements or notes to the condensed consolidated and combined financial statements.

In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as part of its simplification initiative to reduce the cost and complexity in accounting standards.  The ASU requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the related liability.  The treatment is consistent with the current presentation of debt discounts or premiums.  For public business entities, the guidance is effective for financial statements covering fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.  The amended guidance must be applied on a retrospective basis and will not materially affect the Company’s condensed consolidated and combined financial statements or notes to the condensed consolidated and combined financial statements.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

In May 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires entities who value inventory using the first-in, first-out or average cost method to measure inventory at the lower of cost and net realizable value. For public business entities, the amended guidance is effective 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 and combined financial statements or notes to the condensed consolidated and combined financial statements.

 

 

NOTE 3.    DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Instruments and Concentration of Risk

Objective and Strategy

The Company uses derivative financial instruments to manage its exposure to cash flow variability from commodity price risk inherent in its exploration and production activities. These include basis swap contracts and exchange traded over-the-counter crude put spread options and three-way collars with the underlying contract and settlement pricings based on NYMEX West Texas Intermediate (WTI) and Henry Hub.

The Company uses put spread options to manage commodity price risk for 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.

The Company uses three-way collars to manage commodity price risk for both oil and natural gas production. A three-way collar is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. 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.

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.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

Derivative Activities

The following table summarizes the open positions for the commodity derivative instruments held by the Company at June 30, 2015:

 

 

During the first quarter of 2015, the Company elected to lower certain strike prices for both long and short put positions.  By lowering the strike prices for the put spreads, the Company collected approximately $40.7 million of cash for 4,305 notional MBbls, which is reflected in our quarter-end cash balance. There were no such transactions during the second quarter of 2015. 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

The Company excluded from the tables above 9,005 notional MBbls with a fair value of $142.1 million relating to amounts recognized under master netting agreements with derivative counterparties.

Effect of Derivative Instruments on the Condensed Consolidated and Combined Financial Statements

Condensed Consolidated and Combined Balance Sheets

The following table summarizes the gross fair values of the Company’s commodity derivative instruments as of the reporting dates indicated (in thousands):  

 

 

Condensed Consolidated and Combined Statements of Operation

The Company recognized a loss from its derivative activities of $17.7 million and $14.4 million for the three months ended June 30, 2015 and 2014, respectively. The Company recognized a loss from its derivative activities of $10.6 million and $20.0 million for the six months ended June 30, 2015 and 2014, respectively.  These gains and losses are included in the Condensed Consolidated and Combined Statements of Operations line item, Derivative income (loss), as they were not designated as hedges for accounting purposes for any of the periods presented.  The fair value of the derivative instruments is discussed in Note 13—Disclosures about Fair Value of Financial Instruments.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

Offsetting of Derivative Assets and Liabilities

The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and liabilities at settlement or in the event of default under the agreements. Additionally, the Company maintains accounts with its brokers to facilitate financial derivative transactions in support of its risk management activities. Based on the value of the Company’s positions in these accounts and the associated margin requirements, the Company may be required to deposit cash into these broker accounts.  During the three and six months ended June 30, 2015, the Company did not receive or post any margins in connection with collateralizing its derivative positions. At December 31, 2014, the Company received and posted margins with some of its counterparties to collateralize certain derivative positions.

The following table presents the Company’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):

 

 

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 June 30, 2015 and December 31, 2014.

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

NOTE 4.    PROPERTY, PLANT AND EQUIPMENT

 

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

 

 

Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs and current drilling projects.  At June 30, 2015 and December 31, 2014, the Company had excluded $612.4 million and $624.2 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 depreciation, depletion and amortization. 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 $43.1 million and $20.0 million for the three months ended June 30, 2015 and 2014, respectively. Depletion expense on capitalized oil and gas property was $79.5 million and $38.0 million for the six months ended June 30, 2015 and 2014, respectively. The Company had no exploratory wells in progress at June 30, 2015 and December 31, 2014.

The Company capitalizes interest on expenditures made in connection with long-term projects that are not subject to current depletion.  Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest expense. Due to the nature of the Company’s current drilling operations and the timing of payment, there was no interest capitalized during the three and six months ended June 30, 2015.  During the three and six months ended June 30, 2014, the Company capitalized interest of $1.7 million and $2.7 million, respectively.  

Depreciation expense on other property and equipment was $1.3 million and $0.4 million for the three months ended June 30, 2015 and 2014, respectively. Depreciation expense was $2.3 million and $0.8 million for the six months ended June 30, 2015 and 2014, respectively.

 

NOTE 5.    ACQUISITIONS OF OIL AND GAS PROPERTIES

The following 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 six months ended June 30, 2015 and 2014, the Company acquired, from unaffiliated individuals and entities, additional working interests in wells it operates through a number of separate, individually negotiated transactions for an aggregate total cash consideration of $1.6 million and $12.3 million, respectively. There were no such acquisitions during the three months ended June 30, 2015 and 2014. The Company reflected the total consideration paid as part of its costs subject to depletion within its oil and gas properties. The revenues and operating expenses attributable to the working interest acquisitions during the three months ended June 30, 2015 and 2014, were not material.

18

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

On March 27, 2014, the Company entered into a purchase and sale agreement, effective May 1, 2014, pursuant to which it agreed to acquire 2,240 gross (2,005 net) acres in its Midland Basin-Core area and seven gross (6.3 net) wells for total consideration of $165.3 million (the “Pacer Acquisition”), including purchase price adjustments.  The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands):

 

On May 30, 2014, the Company entered into the First Amendment to Option Agreement to which the Company acquired an option to purchase 4,640 gross (4,640 net) acres in its Midland Basin-Core area for total consideration of $127.6 million (the “OGX Acquisition”), net of purchase price adjustments. On June 4, 2014, the option was exercised. The revenues and operating expenses attributable to the OGX Acquisition during the years ended December 31, 2014 and 2013 were not material.  The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands):

 

In addition to the above acquisitions, the Company incurred a total of $8.0 million and $11.8 million in leasehold acquisition costs during the three months ended June 30, 2015 and 2014, respectively, which are included as part of costs not subject to depletion.  The Company incurred a total of $28.2 million and $26.8 million in leasehold acquisition costs during the six months ended June 30, 2015 and 2014, respectively.

19

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(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 as of June 30, 2015 (in thousands):

 

 

NOTE 7.    DEBT

 

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

 

 

Revolving Credit Agreement

On October 21, 2013, the Company entered into an amended and restated credit agreement (as amended, the “Revolving Credit Agreement”) with Wells Fargo Bank National Association as the administrative agent. The Revolving Credit Agreement provides a revolving credit facility with a borrowing capacity up to the lesser of (i) the “Borrowing Base” (as defined in the Revolving Credit Agreement), (ii) aggregate commitments, and (iii) $750.0 million. The Revolving Credit Agreement matures on September 10, 2018. The borrowing base is redetermined by the lenders at least semi-annually on each April 1 and October 1, with the next redetermination to occur on October 1, 2015. The Revolving Credit Agreement is secured by substantially all of the Company’s assets.

On April 21, 2015, the Company entered into the Eighth Amendment to the Revolving Credit Agreement (the “Eighth Amendment”).  The Eighth Amendment amended the Revolving Credit Agreement by, among other things, modifying the terms of the Revolving Credit Agreement to permit Operations to make investments into Pacesetter, in an aggregate amount not to exceed $10 million, subject to additional terms and conditions. Pacesetter is deemed not to be a “Subsidiary”, as defined in and for purposes of the Revolving Credit Agreement, so long as Operations does not own 100% of the aggregate ordinary voting power of the outstanding equity interests of Pacesetter. As a result, Pacesetter will not be required to become a guarantor of the obligations under the Revolving Credit Agreement or grant liens against its assets or properties to secure the obligations under the Revolving Credit Agreement.

In addition, the Eighth Amendment modified the terms of the Revolving Credit Agreement to allow Parsley LP or any Subsidiary to liquidate any swap agreement without a reduction to the Borrowing Base, provided, however that the Borrowing Base will be reduced once the sum of (i) the fair market value of any disposition of oil and gas properties, during the period between “Schedule Redetermination Dates” (as defined in the Revolving Credit Agreement) and (ii) the Borrowing Base value of the liquidated portion of any swap agreements, during the period between Schedule Redetermination Dates, exceeds 5% of the Borrowing Base then in effect.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

Further, the Eighth Amendment increased the Aggregate Elected Borrowing Base Commitments from $365.0 million to $500.0 million and reduced the Borrowing Base from $560.8 million to $500.0 million.

As of June 30, 2015, the borrowing base was $500.0 million, with a commitment level of $500.0 million. There was $45.0 million outstanding related to the Revolving Credit Agreement and $0.3 million in letters of credit outstanding as of June 30, 2015, resulting in availability of $454.7 million.

Borrowings under the Revolving Credit Agreement can be made in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of the Borrowing Base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the adjusted LIBOR rate  plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of our borrowing base utilized. The Revolving Credit Agreement also provides for a commitment fee ranging from 0.375% to 0.500%, depending on the percentage of the Borrowing Base utilized. As of June 30, 2015, letters of credit outstanding under the Revolving Credit Agreement had a weighted average interest rate of 1.75%. The Company may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

The Revolving Credit Agreement requires the Company to maintain the following two financial ratios:

The Revolving Credit Agreement also places restrictions on the Company with respect to additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

At June 30, 2015, the Company was in compliance with all required covenants. The Revolving Credit Agreement is subject to customary events of default, including a Change in Control (as defined in the Revolving Credit Agreement). If an event of default occurs and is continuing, the Majority Lenders (as defined in the Revolving Credit Agreement) may accelerate any amounts outstanding.

7.500% Senior Notes due 2022

On February 5, 2014, Parsley LLC and Finance Corp. issued $400 million of 7.500% senior notes due 2022 (the “Notes”).  Interest is payable on the Notes semi-annually in arrears on each February 15 and August 15, commencing August 15, 2014.  The Notes are guaranteed on a senior unsecured basis by all of the Company’s subsidiaries, other than Parsley LLC, Finance Corp, and Pacesetter.  The issuance of the Notes resulted in net proceeds, after discounts and offering expenses, of approximately $391.4 million, $198.5 million of which was used to repay all outstanding term debt, accrued interest and a prepayment penalty under a second lien credit facility (which was terminated concurrently with such repayment) and $175.1 million of which was used to partially repay amounts outstanding, plus accrued interest, under the Revolving Credit Agreement.

On April 14, 2014, Parsley LLC and Finance Corp. issued an additional $150 million of the Notes at 104% of par for gross proceeds of $156 million.  The issuance of the Notes resulted in net proceeds of approximately $152.8 million, after deducting the initial purchasers’ discount and estimated offering expenses, $145 million of which was used to repay borrowings under the Revolving Credit Agreement.

At any time prior to February 15, 2017, the Company may redeem up to 35% of the Notes at a redemption price of 107.5% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 120 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to February 15, 2017, the Company may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued

21

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

and unpaid interest to the redemption date. On and after February 15, 2017, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 105.625% for the 12-month period beginning on February 15, 2017, 103.750% for the 12-month period beginning February 15, 2018, 101.875% for the 12-month period beginning on February 15, 2019, and 100.00% beginning on February 15, 2020, plus accrued and unpaid interest to the redemption date.

The indenture governing the Notes restricts 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 such covenants 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 June 30, 2015, the Company is in compliance with all required covenants.

Capital Leases

As of June 30, 2015, the Company had entered into an aggregate of $2.4 million in capital lease agreements payable (“Capital Leases”) in connection with the lease of vehicles for operations and field personnel. The Capital Leases bear interest at annual rates ranging from 4.9% to 6.7% with varying maturities between March 2017 and August 2018. The Capital Leases require aggregate monthly payments of $66,079 of principal and interest.

Principal Maturities of Long-Term Debt

Principal maturities of long-term debt outstanding at June 30, 2015 are as follows (in thousands):

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

 

Interest Expense

The following amounts have been incurred and charged to interest expense for the three and six months ended June 30, 2015 and 2014 (in thousands):

 

 

 

NOTE 8.    EQUITY

 

Preferred Stock

 

Pursuant to the Company’s bylaws, the Company’s board of directors, subject to any limitations prescribed by law, may, without further stockholder approval, establish and issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50.0 million shares of preferred stock.  The Company had no shares of preferred stock outstanding at June 30, 2015.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

Class A Common Stock

The Company has a total of approximately 108.8 million shares of its Class A Common Stock outstanding as of June 30, 2015, which includes 0.7 million shares of restricted stock.  Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors.  Upon liquidation, dissolution, distribution of assets or other winding up, the holders of Class A Common Stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and the liquidation preference of any of our outstanding shares of preferred stock.

Class B Common Stock

The Company has a total of approximately 32.1 million shares of its Class B Common Stock outstanding as of June 30, 2015.  Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders.  Holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to the amendment of certain provisions of the Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law.

Holders of Class B Common Stock do not have any right to receive dividends, unless the dividend consists of shares of Class B Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B Common Stock paid proportionally with respect to each outstanding share of Class B Common Stock, and a dividend consisting of shares of Class A Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class A Common Stock on the same terms is simultaneously paid to the holders of Class A Common Stock. Holders of Class B Common Stock do not have any right to receive a distribution upon a liquidation or winding up of the Company.

The PE Unit Holders generally have the right to exchange (the “Exchange Right”) their PE Units (and a corresponding number of shares of Class B Common Stock), for shares of 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 number of shares of Class B Common Stock) exchanged (subject to conversion rate adjustments for stock splits, stock dividends and reclassifications), or cash at the Company’s or Parsley LLC’s election (the “Cash Option”).

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 and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and restricted stock units. For the three and six months ended June 30, 2015 and 2014, respectively, Class B Common Stock, unvested restricted stock and restricted stock unit awards were not recognized in dilutive earnings per share calculations as they would be antidilutive.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(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:

 

 

Incentive Units

Pursuant to the limited liability company agreement of Parsley LLC (the “Parsley LLC Agreement”), certain incentive units were issued to legacy investors, management and employees of Parsley LLC. The incentive units were intended to be compensation for services rendered to Parsley LLC, and were originally separated into four tiers. Tier I incentive units vested ratably over three years, but were subject to forfeiture if payout was not achieved. In addition, all unvested Tier I incentive units vested immediately upon Tier I payout. Tier I payout was realized upon the return of the Preferred Holders’ invested capital and a specified rate of return. Tier II, III and IV incentive units vested only upon the achievement of certain payout thresholds for each such tier and each tier of the incentive units was subject to forfeiture if the applicable required payouts were not achieved. In addition, vested and unvested incentive units would be forfeited if an incentive unit holder’s employment was terminated for any reason or if the incentive unit holder voluntarily terminated their employment.

The incentive units were accounted for as liability-classified awards pursuant to ASC Topic 718, “Compensation—Stock Compensation,” as achievement of the payout conditions required the settlement of such awards by transferring cash to the incentive unit holder. As such, the fair value of the incentive unit was remeasured each reporting period through the date of settlement, with the percentage of such fair value recorded to compensation expense each period being equal to the percentage of the requisite explicit or implied service period that has been rendered at that date.  In connection with the Corporate Reorganization, all of the incentive units were immediately vested and converted into PE Units and, subsequently, a portion of such PE Units were exchanged on a one for one basis for shares of Class A Common Stock.  As a result, Parsley LLC was required to recognize, as a non-cash charge, the unrecognized cumulative incentive unit compensation expense of approximately $50.6 million on May 29, 2014, in addition to the

25

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

$0.5 million recognized during the period from January 1, 2014 through May 29, 2014.  There was no incentive unit compensation recognized during the three and six months ended June 30, 2015.

Noncontrolling Interest

Concurrent with the closing of the Pacesetter Acquisition, a principal of and prior interest holder in the selling entity in the Pacesetter Acquisition acquired a 37.0% interest in Pacesetter, with Operations retaining 63.0% of Pacesetter.  As a result, the Company has consolidated the financial position and results of operations of Pacesetter and reflected that portion retained by the previous owners as a noncontrolling interest.

Upon completion of the Private Placement in February 2015, the Company’s ownership of Parsley LLC increased to 77.2%, with the PE Unit Holders’ ownership of Parsley LLC decreasing to 22.8%. The Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the PE Unit Holders as a noncontrolling interest.

Because the increase in the Company’s ownership interest in Parsley LLC does not result in a change of control, the transaction is accounted for as an equity transaction under ASC Topic 810, “Consolidation,” which requires that any differences between the amount by which the carrying value of the Company’s basis in Parsley LLC is adjusted and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. 

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

 

 

NOTE 9.    STOCK BASED COMPENSATION

In connection with the Offering, 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 “Executive Compensation and Other Information—Narrative Disclosure to Summary Compensation Table—2014 Long-Term Incentive Plan” in the Company’s Proxy Statement filed on Schedule 14A for the 2015 Annual Meeting of Stockholders for additional information related to this equity based compensation plan.

Restricted Stock

Restricted stock awards are awards of Class A Common Stock that are subject to restrictions on transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions. The stock based compensation expense for these awards was determined using the closing price on the date of grant applied to the total number of shares that were anticipated to fully vest.

Time-Based Restricted Stock Unit Awards

Restricted stock unit awards represent the right to receive Class A Common Stock at the end of the vesting period equal to the number of restricted stock units granted.  Restricted stock units are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restriction.  The stock based compensation expense of such restricted stock units was determined using the closing price on the date of grant applied to the total number of shares that were anticipated to fully vest.

26

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

Performance Unit Awards

In February 2015, performance-based, stock-settled restricted stock unit awards, which we refer to as performance unit awards, were granted with a performance period of three years.  The number of shares of Class A Common Stock actually delivered pursuant to these performance unit awards depends on the Company’s performance over the performance period with respect to certain predetermined market conditions.  The Company granted a target number of 211,935 performance unit awards, 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 payout level is calculated based on actual performance achieved during the performance period compared to a defined peer group.

The following table summarizes the Company’s restricted stock, restricted stock unit award, and performance unit activity for the six months ended June 30, 2015:

 

Stock based compensation expense related to restricted stock, restricted stock units, and performance units was $2.1 million and $0.3 million for the three months ended June 30, 2015 and 2014, respectively.  Stock based compensation expense was $3.8 million $0.3 and million for the six months ended June 30, 2015 and 2014, respectively.  There was approximately $21.4 million of unamortized compensation expense relating to outstanding restricted stock, restricted stock units, and performance units at June 30, 2015.

 

NOTE 10.    INCOME TAXES

The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. The Company believes it is more likely than not that certain net operating losses can be carried forward and utilized.

Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to United States (“U.S.”) federal income tax. As part of the Corporate Reorganization, certain of the Existing Owners exchanged all or part of their PE Units for shares of the Company’s common stock, as discussed in Note 1 – Organization and Nature of Operations. On the date of the Corporate Reorganization, a corresponding “first day” tax charge of approximately $95.5 million was recorded to establish a net deferred tax liability for differences between the tax and book basis of Parsley LLC’s assets and liabilities. In addition, as of June 30, 2015, the liability associated with the TRA (as defined in Note 11—Related Party Transactions) was $50.7 million and the corresponding deferred tax asset was $59.6 million.

27

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

As a result of the Private Placement, as discussed in Note 1—Organization and Nature of Operations, the Company’s statutory rate related to certain tax and book basis timing differences increased by 1%, calculated by multiplying the 2.8% increase in the Company’s ownership of Parsley LLC by the Company’s federal tax rate of 35%.  As a result, the Company recorded additional deferred tax liability of $7.0 million during the three months ended March 31, 2015. 

The Company is a corporation and it is subject to U.S. federal income tax. The tax implications of the 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 and combined financial statements. The effective combined U.S. federal and state income tax rate as of June 30, 2015 was 24.0%.  During the three months ended June 30, 2015 and 2014, the Company recognized an income tax benefit of $10.2 million and an income tax expense of $1.8 million, respectively. During the six months ended June 30, 2015 and 2014, the Company recognized an income tax benefit of $15.7 million and an income tax expense of $2.3 million, respectively. Total income tax expense for the three and six months ended June 30, 2015 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to state taxes and the impact of earnings attributable to noncontrolling ownership interests.

NOTE 11.    RELATED PARTY TRANSACTIONS

Well Operations

During the three and six months ended June 30, 2015 and 2014, 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 June 30, 2015 and 2014, totaled $1.2 million and $3.6 million, respectively. The revenues disbursed to such Related Party Working Interest Owners for the six months ended June 30, 2015 and 2014, totaled $2.2 million and $7.0 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.

Tex-Isle Supply, Inc. Purchases

The Company makes purchases of equipment used in its drilling operations from Tex-Isle Supply, Inc. (“Tex-Isle”).  Tex-Isle is controlled by a party who is also the general partner of Diamond K Interests, LP (“Diamond K”), a former member of Parsley LLC. In connection with the Offering, Diamond K exchanged its membership interest for shares of Class A Common Stock.  As of May 29, 2014, Diamond K is no longer considered a related party as its ownership interest fell below 10%, which results in Tex-Isle no longer being considered a related party.  During the two and five months ended May 29, 2014, the Company made purchases of equipment used in its drilling operations totaling $17.1 million and $25.0 million from Tex-Isle.

Spraberry Production Services LLC

The Company owns a 42.5% interest in SPS (as defined in Note 2—Basis of Presentation).  During the three months ended June 30, 2015 and 2014, the Company incurred charges totaling $0.8 million and $0.7 million, respectively, for services performed by SPS for the Company’s well operations and drilling activities.  During the six months ended June 30, 2015 and 2014, the Company incurred charges totaling $2.6 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 rents equipment and services used in its drilling operations from Lone Star Well Service, LLC (“Lone Star”), which is controlled by SPS.  During the three and six months ended June 30, 2015, the Company incurred charges totaling $1.2 million and $2.1 million, respectively, for services performed by Lone Star for the Company’s wells operations and drilling activities.  There were no such charges incurred during the three and six months ended June 30, 2014.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

Davis, Gerald, and Cremer, PC

During the three months ended June 30, 2015 and 2014, we incurred charges totaling $0.1 million and $0.1 million, respectively, for legal services from Davis, Gerald & Cremer, PC, of which our director David H. Smith is a shareholder.  During the six months ended June 30, 2015 and 2014, we incurred charges totaling $0.2 million and $0.1 million, respectively, for legal services from Davis, Gerald & Cremer, PC.

Exchange Right

In accordance with the terms of the amended 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 Offering, 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 Offering (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 Offering as a result of (i) any tax basis increases resulting from the contribution in connection with the Offering 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 commences 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.

 

NOTE 12.    SIGNIFICANT CUSTOMERS

 

For the six months ended June 30, 2015 and 2014, each of the following purchasers accounted for more than 10% of the Company’s revenue:  

 

 

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.

 

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

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:

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The book value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair value due to the short-term nature and negligible credit risk of these instruments.  The book value of the Company’s Revolving Credit Agreement approximates its fair value as the interest rate is variable and there are no indicators for change in the Company’s market spread.

The estimated fair value of the Company’s $550 million of Notes at June 30, 2015, was approximately $560.8 million. The fair value of the Notes is classified as a level 1 measurement as it is calculated based on market quotes.

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

June 30, 2015

(Unaudited)

 

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 and Combined 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):

 

 

 

 

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 that required disclosure or recognition in these financial statements.

 

 

 

 

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

 

Our Predecessor and Parsley Energy, Inc.

 

Parsley Energy Inc. (either individually or together with its subsidiaries, as the context requires, the “Company”) was formed in December 2013 and does not have historical financial operating results. For purposes of this discussion, our accounting predecessors are Parsley LLC and its predecessors, Operations and Parsley LP.  Both Operations and Parsley LP began operations in 2008 in conjunction with the acquisition of operator rights to wells producing from the Spraberry Trend in the Midland Basin.  Parsley LLC was formed in June 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves in the Permian Basin. Concurrent with the formation of Parsley LLC, all of the interest holders in Parsley LP, the General Partner, and Operations exchanged their interests in each such entity for interests in Parsley LLC (the “Exchange”). The Exchange was treated as a reorganization of entities under common control.  

 

We are a holding company whose sole material asset consists of PE Units. We are the managing member of 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.

 

Overview

 

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 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 June 30, 2015, our acreage position was 182,513 gross (132,367 net) acres. The vast majority of our acreage is located in the Midland Basin, and over 90% 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 June 30, 2015, we operated approximately 692 vertical wells across our acreage in the Midland Basin. Since commencing our horizontal drilling program in 2014 through June 30, 2015, we have drilled and placed on production 37 horizontal wells in the Midland Basin, of which seven and 19 were placed on production during the three and six months ended June 30, 2015, respectively. As of June 30, 2015, we operated 46 horizontal wells.  Additionally, we commenced our vertical appraisal drilling program in the Delaware Basin during the first quarter of 2014.  At June 30, 2015, we had drilled and completed three vertical appraisal wells in the Delaware Basin. As of December 31, 2014, we have identified 2,125 potential horizontal drilling locations, 1,893 80- and 40-acre potential vertical drilling locations and 2,403 20-acre potential vertical drilling locations on our existing acreage, which does not include any locations in Gaines County (Midland Basin) or in our Southern Delaware Basin acreage. As of June 30, 2015, we had interests in 719 gross (448 net) producing wells across our properties and operated 99% of the wells in which we had an interest.

 

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How We Evaluate Our Operations

 

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

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 June 30, 2015 and 2014, our revenues were derived 81% and 75%, respectively, from oil sales; 9% and 12%, respectively, from natural gas sales; and 10% and 13%, respectively, from NGLs sales. For the six months ended June 30, 2015 and 2014, our revenues were derived 80% and 77%, respectively, from oil sales; 10% and 11%, respectively, from natural gas sales; and 9% and 13%, 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 and six months ended June 30, 2015 and 2014.

 

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 development activities 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 June 30, 2015, West Texas Intermediate posted prices ranged from $49.14 to $61.43 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $3.02 per MMBtu.  During the three months ended June 30, 2014, West Texas Intermediate posted prices ranged from $99.42 to $107.26 per Bbl and the Henry Hub spot market price of natural gas ranged from $4.28 to $4.83 per MMBtu.  During the six months ended June 30, 2015, West Texas Intermediate posted prices ranged from $43.46 to $61.43 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $3.23 per MMBtu.  During the six months ended June 30, 2014, West Texas Intermediate posted prices ranged from $91.66 to $107.26 per Bbl and the Henry Hub spot market price of natural gas ranged from $4.00 to $6.15 per MMBtu.  

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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.

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 including hedging our natural gas production. We are not under an obligation to hedge a specific portion of our oil or natural gas production.

Our positions hedging production as of June 30, 2015 were as follows:

 

 

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

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

Recent and Formation Transactions

The historical results of operations through May 29, 2014 are based on the financial statements of our accounting predecessor, which reflects the combined results of Parsley LLC, prior to the Offering and the concurrent corporate reorganization (“Corporate Reorganization”), which increased the scope of our operations.

Stock Based Compensation

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

Public Company Expenses

We expect to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, increased scope of our operations as a result of recent activities and costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, legal fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations prior to the Corporate Reorganization.

Income Taxes

Our accounting predecessors are limited liability companies or limited partnerships and therefore not subject to United States (“U.S.”) federal income taxes. Accordingly, no provision for U.S. federal income tax has been provided for in our historical results of operations.  We are taxed as a corporation under the Internal Revenue Code and subject to U.S. federal income tax at a statutory rate of 35% of pretax earnings, and, as such, the amount of our future U.S. federal income tax will be dependent upon our future taxable income.

The Company’s operations located in Texas are subject to an entity-level tax, the Texas margin tax, at a statutory rate of up to 1.0% of Texas income.

Drilling Activity

As of June 30, 2015, we operated four horizontal drilling rigs on our properties. For the six months ended June 30, 2015, our capital expenditures for drilling and completions were $196.7 million, as compared to $491.3 million for all of fiscal year 2014.  

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.

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Results of Operations

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

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:

 

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The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationship 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.

 

Oil revenues increased 3% to $63.4 million during the three months ended June 30, 2015 from $61.7 million during the three months ended June 30, 2014. The increase is attributable to the increase in volumes sold of 529 MBbls of oil which is offset by a $40.79 per barrel decrease in average oil prices to $53.61 per barrel for the three months ended June 30, 2015. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $49.9 million while decreases in oil prices accounted for a negative change of $48.2 million.

Natural gas revenues decreased by 31% to $6.7 million during the three months ended June 30, 2015 from $9.7 million during the three months ended June 30, 2014. The revenue decrease is a result of a $2.34 per MMcf decrease in our average realized natural gas prices to $2.48 per MMcf, for the three months ended June 30, 2015 which was partially offset by an increase in volumes sold of 678 MMcf. Of the overall changes in natural gas sales, increases in natural gas production volumes accounted for a positive change of $3.3 million while the decrease in natural gas prices account for a negative change of $6.3 million.

NGLs revenues decreased by 29% to $7.7 million during the three months ended June 30, 2015 from $10.8 million during the three months ended June 30, 2014.  The decrease is attributable to a $18.55 per Boe decrease in average NGLs prices to $19.76, which was partially offset by an increase in volumes sold of 109 Boe.  Of the overall change in NGLs, production volumes accounted for a positive change of $4.2 million while the decreases in NGLs prices accounted for a negative change of $7.3 million.

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

 

* Not meaningful 

Lease Operating Expenses. Lease operating expenses increased 91% to $18.5 million during the three months ended June 30, 2015 from $9.7 million during the three months ended June 30, 2014. The increase is primarily due to the higher operated well count in the three months ended June 30, 2015 as compared to the three months ended June 30, 2014. On a per Boe basis, lease operating expenses increased to $9.12 per Boe from $7.59 per Boe during this period. This increase was attributable to an increase in costs for saltwater disposal, workovers, and repairs and maintenance.

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased 1% to $5.4 million during the three months ended June 30, 2015 from $5.5 million during the three months ended June 30, 2014 due to decreased revenue resulting from decreased average prices.

Depreciation, Depletion and Amortization. Depreciation, depletion, and amortization expense increased by 117% to $44.4 million or $21.93 per BOE for the three months ended June 30, 2015 from $20.4 million or $16.05 per BOE during the three months ended June 30, 2014 due to an increase in capitalized costs and production volumes.

General and Administrative Expenses. General and administrative expenses increased 73% to $12.3 million during the three months ended June 30, 2015 from $7.1 million during the three months ended June 30, 2014 primarily due to higher payroll and payroll-related costs associated with the hiring of additional employees to manage our growing asset base and professional fees incurred in conjunction with operating as a public company.

Exploration Costs. Exploration costs of $1.5 million during the three months ended June 30, 2015 are comprised of approximately $1.4 million of geological and geophysical expenses, which primarily consist of the costs of acquiring and processing seismic data, geophysical data and core analysis. Exploration costs include approximately $0.1 million of non-cash leasehold amortization expense directly related to unproved leasehold costs. No exploration costs were incurred during the three months ended June 30, 2014.

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Incentive Unit Compensation.  There was no incentive unit compensation expense for the three months ended June 30, 2015.  Incentive unit compensation of $50.5 million during the three months ended June 30, 2014 is attributable to the one time incentive unit expense in connection with the Corporate Reorganization.

Stock Based Compensation. Stock based compensation increased $1.8 million to $2.1 million for the three months ended June 30, 2015 from $0.3 million for the three months ended June 30, 2014, and was directly related to the amortization of the restricted stock, restricted stock units, and performance units outstanding during the three months ended June 30, 2015. The increase in stock based compensation is due to additional restricted stock, restricted stock units, and performance units being issued since June 30, 2014.

Rig Termination.  During the three months ended June 30, 2015, we paid a total of $3.9 million in rig termination expenses, which is comprised of approximately $0.3 million related to the termination of drilling rig contracts entered into in 2014 and approximately $3.6 million for stacking fees associated with certain drilling rig contracts.  There were no such expenses incurred during the three months ended June 30, 2014.

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

 

* Not meaningful 

Interest Expense. Interest expense increased 8% to $10.7 million in the three months ended June 30, 2015 from $9.9 million during the three months ended June 30, 2014 primarily due to accrued interest related to the Notes, of which only $400 million were outstanding through April 2014.  During April 2014, we issued an additional $150 million of the Notes.  This issuance results in the weighted average outstanding debt being greater during the three months ended June 30, 2015 as compared to the three months ended June 30, 2014.

Derivative Income (Loss). Loss on derivative instruments increased 24% to $17.7 million during the three months ended June 30, 2015, compared to a loss of $14.4 million during the three months ended June 30, 2014 primarily as a result of the unfavorable commodity price changes for derivatives but favorable commodity price changes for operations on increased hedging activities.

Other income (expense). Other income (expense) increased to $1.5 million during the three months ended June 30, 2015 from the three months ended June 30, 2014.  The increase is largely attributable to $1.2 million of license fee income, which is related to licensing of certain geological and geophysical seismic data. In addition, income from equity investments increased approximately $0.7 million during the three months ended June 30, 2015 from the three months ended June 30, 2014, which is offset by an increase of approximately $0.4 million of other miscellaneous business related expenses.

Income Tax Benefit (Expense)

The effective combined U.S. federal and state income tax rate as of June 30, 2015 was 24.0%.  As a pass-through entity, our predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S. federal income tax.  During the three months ended June 30, 2015, we recognized a tax benefit of $10.2 million, an increase of $12.0 million as compared to the $1.8 million tax expense we recognized during the three months ended June 30, 2014. The increase was attributable to the corresponding decrease in net income during the applicable periods.  During the three months ended June 30, 2015, we were subject to the federal income tax rate for the entire period as compared to only one month during the three months ended June 30, 2014.

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Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

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:

 

 

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The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationship 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.

 

Oil revenues decreased by $0.5 million to $107.1 million during the six months ended June 30, 2015 from $107.6 million during the six months ended June 30, 2014. The decrease is attributable to a $45.08 per barrel decrease in average oil prices to $48.86 per barrel for the six months ended June 30, 2015, which is mostly offset by the increase in volumes sold of 1,047 MBbls of oil. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $98.4 million while decreases in oil price accounted for a negative change of $98.9 million. Our production volumes increased due to increased drilling activities and acquisitions during the period between the quarters.

Natural gas revenues decreased by 8% to $13.7 million during the six months ended June 30, 2015 from $14.8 million during the six months ended June 30, 2014. The revenue decrease is a result of a $2.14 per MMcf decrease in our average realized natural gas prices to $2.73 per MMcf, for the six months ended June 30, 2015, which was partially offset by an increase in volumes sold of 1,964 MMcf. Of the overall changes in natural gas sales, increases in natural gas production volumes accounted for a positive change of $9.6 million while the change in natural gas price account for a negative change of $10.7 million.

NGLs revenues decreased by 30% to $12.3 million during the six months ended June 30, 2015 from $17.7 million during the six months ended June 30, 2014.  The decrease is attributable to a $21.97 per Boe decrease in average NGLs prices to $17.54, which was partially offset by an increase in volumes sold of 254 Boe.  Of the overall change in NGLs, increases in NGLs production volumes accounted for a positive change of $10.0 million while the decrease in NGLs price accounted for a negative change of $15.4 million.

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

 

* Not meaningful 

Lease Operating Expenses. Lease operating expenses increased $18.2 million to $34.9 million during the six months ended June 30, 2015 from $16.7 million during the six months ended June 30, 2014. The increase is primarily due to the higher operated well count in the six months ended June 30, 2015 as compared to the six months ended June 30, 2014. On a per Boe basis, lease operating expenses increased to $9.35 per Boe from $7.95 per Boe during this period. This increase was mostly attributable to an increase in costs for saltwater disposal and workovers.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 17% to $9.9 million during the six months ended June 30, 2015 from $8.5 million during the six months ended June 30, 2014 due to increased ad valorem taxes from the six months ended June 30, 2014 and offset by a decrease in production taxes, which is attributable to the decreased pricing.

Depreciation, Depletion and Amortization. Depreciation, depletion, and amortization expense increased $43.0 million to $81.8 million or $21.94 per BOE for the six months ended June 30, 2015 from $38.8 million or $18.50 per BOE during the six months ended June 30, 2014 due to an increase in capitalized costs and production volumes.

General and Administrative Expenses. General and administrative expenses increased 61% to $24.0 million during the six months ended June 30, 2015 from $14.9 million during the six months ended June 30, 2014 primarily due to higher payroll and payroll-related costs associated with the hiring of additional employees to manage our growing asset base, higher rig count and increased production.

Exploration Costs. Exploration costs of $4.7 million during the six months ended June 30, 2015 are comprised of approximately $1.8 million of non-cash leasehold impairment expense directly related to future leasehold expirations and unproved leasehold amortization.  Exploration costs also include approximately $2.9 million of geological and geophysical expenses, which primarily consist of the costs of acquiring and processing seismic data, geophysical data and core analysis. No exploration costs were incurred during the six months ended June 30, 2014.

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Incentive Unit Compensation.  There was no incentive unit compensation expense for the six months ended June 30, 2015.  Incentive unit compensation of $51.1 million during the six months ended June 30, 2014 is attributable to the one time incentive unit compensation expense recognized upon the Corporate Reorganization.

Stock Based Compensation. Stock based compensation increased $3.5 million to $3.8 million for the six months ended June 30, 2015 from $0.3 million for the six months ended June 30, 2014 due to additional restricted stock, restricted stock units, and performance units being issued subsequent to June 30, 2014.

Rig Termination.  During the six months ended June 30, 2015, we paid a total of $9.0 million in rig termination expenses, which is comprised of approximately $4.4 million related to the termination of drilling rig contracts entered into in 2014 and approximately $4.6 million for stacking fees associated with certain drilling rig contracts.  There were no such expenses incurred during the six months ended June 30, 2014.

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

 

* Not meaningful 

Interest Expense. Interest expense increased 25% to $22.2 million in the six months ended June 30, 2015 from $17.8 million during the six months ended June 30, 2014 primarily due to accrued interest related to the Notes, of which only $400 million were outstanding during the six months ended June 30, 2014 as compared to $550 million outstanding during the six months ended June 30, 2015.

Prepayment Premium on Extinguishment of Debt.  During the six months ended June 30, 2014, we incurred a $5.1 million charge related to a prepayment penalty on our then outstanding second lien term loan.  There were no such expenses incurred during the six months ended June 30, 2015.

Derivative Income (Loss). Loss on derivative instruments decreased 47% to $10.6 million during the six months ended June 30, 2015 from $20.0 million during the six months ended June 30, 2014 primarily as a result of the unfavorable commodity price changes for operations but favorable commodity price changes for derivatives on increased hedging activities.

Other income (expense). Other income (expense) increased by $1.5 million to income of $1.8 million during the six months ended June 30, 2015 from income of $0.3 million during the six months ended June 30, 2014.  The increase is attributable to $1.2 million of license fee income earned during the six months ended June 30, 2015.  In addition, income from equity investments increased approximately $0.7 million during the six months ended June 30, 2015 from the six months ended June 30, 2014, which is offset by a decrease in other miscellaneous income of approximately $0.4 million.

Income Tax Benefit (Expense)

The effective combined U.S. federal and state income tax rate as of June 30, 2015 was 24.0%.  As a pass-through entity, our predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S. federal income tax through May 29, 2014.  During the six months ended June 30, 2015, we recognized a tax benefit of $15.7 million, an increase of $13.4 million as compared to the $2.3 million expense we recognized during the three months ended June 30, 2014. The increase was attributable to the corresponding decrease in net income during the applicable periods. During the six months ended June 30, 2015, we were subject to the federal income tax rate for the entire period as compared to only one month during the six months ended June 30, 2014.

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Liquidity and Capital Resources

We expect that our primary sources of liquidity and capital resources will be cash flows generated by operating activities and borrowings under our amended and restated credit agreement (as amended, the “Revolving Credit Agreement”) with Wells Fargo Bank, National Association, as the administrative agent. Depending upon market conditions and other factors, we may also seek to access the capital markets to meet our liquidity needs and capital requirements.  

Our primary use of capital is for the development and exploration of oil and natural gas properties and increasing our acreage position. Our total debt was $596.9 million and $672.1 million as of June 30, 2015 and December 31, 2014, respectively. Total borrowings during those periods were used primarily to fund development and exploration of oil and natural gas properties in addition to adding to our leasehold interests.

Capital Requirements and Sources of Liquidity

For the six months ended June 30, 2015, our aggregate drilling and completion capital expenditures were $196.7 million. During the year ended December 31, 2014, our aggregate drilling and completion capital expenditures were $491.3 million.  These capital expenditure totals exclude acquisitions.  Substantially all of our remaining capital expenditures in 2015 for drilling and completion will be spent in the Midland Basin.

The amount and timing of 2015 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2015 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners.

Based upon current oil and natural gas price expectations, we believe that our cash on hand, cash flow from operations and borrowings under our Revolving Credit Agreement will be sufficient to execute our current capital program excluding any acquisitions we may enter into. 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 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, 2014 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 2015 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.

 

Cash Flows

 

The following table summarizes our cash flows for the periods indicated:

 

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Cash Flow Provided by Operating Activities.  Net cash provided by operating activities was approximately $78.6 million and $53.6 million for the six months ended June 30, 2015 and 2014, respectively. Net cash provided by operating activities increased from the period ending June 30, 2014 to June 30, 2015 primarily due to the cash received for option premiums and cash received for derivative settlements as discussed in Note 3—Derivative Financial Instruments to our condensed consolidated and combined financial statements included elsewhere in this Quarterly Report.  This increase is offset by the decrease in operating income, which is primarily attributable to a decrease in our production margin resulting from a 61% increase in our cash based operating expenses, which include lease operating expenses, production and ad valorem taxes, general and administrative expenses, and exploration costs.  Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production volumes.

Cash Flow Used in Investing Activities.  Net cash used in investing activities was approximately $255.9 million and $527.7 million for the six months ended June 30, 2015 and 2014, respectively. The decreased amount of cash used in investing activities during the six months ended June 30, 2015, as compared to the six months ended June 30, 2014, was due primarily to the $302.3 million decrease in acquisition costs during the six months ended June 30, 2015 over the six months ended June 30, 2014.

Cash Flow Provided by Financing Activities.  Net cash provided by financing activities was approximately $147.9 million and $978.2 million for the six months ended June 30, 2015 and 2014, respectively. Net cash provided by financing activities decreased during the period ending June 30, 2015 from the period ending June 30, 2014 due to net proceeds from our initial public offering of $867.8 million and net debt borrowings in excess of payments of $128.7 million during the six months ended June 30, 2014. During the six months ended June 30, 2015, the Company received net proceeds of $224.0 million from the February 2015 private placement of our Class A common stock, par value $0.01 per share, and made net debt payments in excess of borrowings of $75.0 million.

Capital Sources

Revolving Credit Agreement. See Note 7—Debt to our condensed consolidated and combined 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 and combined financial statements included elsewhere in this Quarterly Report for a description of 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 over a two-to-three year period at a given point in time.

Working Capital.  Our working capital totaled $(72.4) million and $(16.7) million at June 30, 2015 and December 31, 2014, respectively. Our collection of receivables has historically been timely and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $21.1 million and $50.6 million at June 30, 2015 and December 31, 2014, respectively. The $29.5 million decrease in cash is primarily attributable to the increase in operating expenses in conjunction with the slight decrease in revenues, which is largely attributable to the $32.88 decrease in average oil price including the effects of derivatives for the six months ended June 30, 2015. Due to the amounts that accrue 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 June 30, 2015, to the methodology applied by management for critical accounting policies previously disclosed in our Annual Report.  Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report for a description of the Company’s critical accounting policies.

Off-Balance Sheet Arrangements

As of June 30, 2015, we have no off-balance sheet arrangements.

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Item 3.    Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas, and NGLs 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, natural gas, and NGLs production. Pricing for oil, natural gas, and NGLs 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, natural gas, and NGLs 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 and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure to oil price fluctuations.  The Company also 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.  For a description of our open positions at June 30, 2015, see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Sources of our Revenues.”

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 June 30, 2015, the fair market value of our oil derivative contracts was a net asset of $42.2 million.  Based on our open oil derivative positions at June 30, 2015, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $9.3 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $13.4 million.  As of June 30, 2015, the fair market value of our natural gas derivative contracts was a net asset of $1.1 million.  Based upon our open commodity derivative positions at June 30, 2015, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately $0.1 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas derivative asset by less than $0.1 million.

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. 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.  The impact of a one percent increase in interest rates for our Revolving Credit Agreement, based on the amount outstanding as of June 30, 2015, would result in increased annual interest expense of approximately $0.5 million.

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Item 4.    Controls and Procedures

 

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) under the Exchange Act) as of June 30, 2015.  Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.  Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2015, 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 June 30, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

 

 

 

 

 

 

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PART II.  OTHER INFORMATION

Item 1.    Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our Annual Report, 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.  

Item 6.    Exhibits

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

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SIGNATURES

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

 

 

 

 

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EXHIBIT INDEX

 

 

 

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