UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended September 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 November 6, the registrant had 123,712,043 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 SEPTEMBER 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:

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

 

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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 Energy, LLC were converted to in connection with our 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 or existing 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.” Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

“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

September 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, and is engaged in the acquisition and development of unconventional oil and natural gas reserves located in the Permian Basin, which is located in West Texas and Southeastern New Mexico.

Private Placement of Common Stock

On February 5, 2015, the Company entered into an agreement to sell 14,885,797 shares of its Class A common stock, par value $0.01 per share (“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 to Parsley Energy, LLC (“Parsley LLC”) in exchange for 14,885,797 PE Units.  As a result, the Company’s ownership of Parsley LLC increased to 77.2%, with the remaining holders’ of PE Units (the “PE Unit Holders”) ownership of Parsley LLC decreasing to 22.8%.

Pacesetter Drilling, LLC

On April 21, 2015, Parsley Energy 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 with an oilfield drilling company to acquire certain property, equipment, and other assets (the “Pacesetter Acquisition”).  The Pacesetter Acquisition was accounted for using the acquisition method under Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations.” Operations and Pacesetter’s President contributed cash in exchange for ownership in Pacesetter.  Pacesetter then paid total consideration of $7.0 million for its interest in the purchased assets, of which $4.4 million was allocated to Operations and $2.6 million was allocated to the noncontrolling interest.  As a result of the Pacesetter Acquisition, Operations has a 63.0% interest in Pacesetter.

Public Offering of Common Stock

On September 18, 2015, the Company entered into an agreement to sell 14,950,000 shares of its Class A Common Stock (including 1,950,000 shares issued pursuant to the underwriters’ option to purchase additional shares) at a price of $15.00 per share in an underwritten public offering (the “September Offering”). The September Offering resulted in gross proceeds of approximately $224.3 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $217.0 million. A portion of the net proceeds were used to repay borrowings outstanding under the Company’s amended and restated credit agreement (as amended, the “Revolving Credit Agreement”) with Wells Fargo Bank, National Association, as the administrative agent, and the remainder of the net proceeds are expected to be used to fund a portion of the Company’s capital program, which may include acquisitions.

Upon completion of the September Offering, the Company contributed all of the net proceeds to Parsley LLC in exchange for 14,950,000 PE Units.  As a result, the Company’s ownership of Parsley LLC increased to 79.4%, with the PE Unit Holders’ ownership of Parsley LLC decreasing to 20.6%.

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, a majority-owned subsidiary of Operations. Parsley LP owns a 42.5% noncontrolling interest in Spraberry Production Services LLC (“SPS”). The Company accounts for its investment in SPS using the equity method of accounting.  All significant intercompany and intra-company balances and transactions have been eliminated.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

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 nine month periods ending September 30, 2015, are not necessarily indicative of the operating results of the entire fiscal year ending December 31, 2015.

Significant Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of net sales and expenses during the reporting periods. Actual results could differ from those estimates. For a complete description of the Company’s significant accounting policies and critical estimates, see Note 3—Summary of Significant Accounting Policies in the Annual Report.

 

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 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.  These reclassifications include the reclassification of a one-time non-cash compensation expense of $51.1 million from Incentive Unit Compensation to Stock Based Compensation on the condensed consolidated and combined Statement of Operations and condensed consolidated and combined Statement of Cash Flows for the nine months ended September 30, 2014.  These reclassifications also include the reclassification of NGLs sales of $5.5 million and $17.8 million from Natural Gas Sales to Natural Gas Liquids Sales on the condensed consolidated and combined Statement of Operations for the three and nine months ended September 30, 2014.

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.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

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.

In May 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires entities that value inventory using the first-in, first-out or average cost method to measure inventory at the lower of cost and net realizable value. 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 utilizes commodity swap contracts, three-way collars, and put spread options to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects.

Derivative Activities

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

The following table sets forth the volumes associated with the Company's outstanding oil derivative contracts as of September 30, 2015 and the weighted average oil prices for those contracts: 

 

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

During 2015, the Company has periodically 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 $4.8 million of cash for 4,110 notional MBbls during the three months ended September 30, 2015, which is reflected in its quarter-end cash balance. The Company collected approximately $45.6 million for 8,415 notional MBbls during the nine months ended September 30, 2015.  

Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("HH") gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and the actual index prices at which the gas is sold.

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of September 30, 2015 and the weighted average gas prices for those contracts:

 

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

All of the Company’s derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur.  The Company recognized income from its derivative activities of $34.3 million and $11.8 million for the three months ended September 30, 2015 and 2014, respectively. The Company recognized income from its derivative activities of $23.7 million and a loss of $8.3 million for the nine months ended September 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).

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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

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 September 30, 2015 and December 31, 2014.

 

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 September 30, 2015 and December 31, 2014, the Company had excluded $623.7 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

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

expense on capitalized oil and gas property was $44.8 million and $20.0 million for the three months ended September 30, 2015 and 2014, respectively. Depletion expense on capitalized oil and gas property was $124.3 million and $58.0 million for the nine months ended September 30, 2015 and 2014, respectively. The Company had no exploratory wells in progress at September 30, 2015 and December 31, 2014.

 

NOTE 5.    ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES

Acquisitions

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 three months ended September 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 $12.2 million and $7.5 million, respectively. During the nine months ended September 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 $14.1 million and $19.8 million, respectively. 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 and nine months ended September 30, 2015 and 2014, were not material.  

In addition to the above acquisitions, the Company incurred a total of $23.0 million and $40.8 million in leasehold acquisition costs during the three months ended September 30, 2015 and 2014, respectively, which are included as part of costs not subject to depletion.  The Company incurred a total of $50.8 million and $67.6 million in leasehold acquisition costs during the nine months ended September 30, 2015 and 2014, respectively.

Divestitures

In July 2015, the Company sold 9,164 net acres for total proceeds of $9.3 million and recognized a gain on the sale of $3.2 million.

In August 2014, the Company sold its interest in one operated well and 38 net acres for total proceeds of $0.2 million and recognized a $2.1 million loss on the sale.

 

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 September 30, 2015 (in thousands):

 

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

NOTE 7.    DEBT

 

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

 

 

Revolving Credit Agreement

As of September 30, 2015, the “Borrowing Base” under the Revolving Credit Agreement (as defined therein) was $500.0 million, with a commitment level of $500.0 million. There was no outstanding balance related to the Revolving Credit Agreement and $0.3 million in letters of credit outstanding as of September 30, 2015, resulting in availability of $499.7 million.

On November 3, 2015, the Company entered into the Ninth Amendment to the Revolving Credit Agreement (as discussed in further detail in Note 14—Subsequent Events) whereby the “Aggregate Elected Borrowing Base Commitments” (as defined in the Revolving Credit Agreement) were increased from $500.0 million to $575.0 million, and the Borrowing Base was increased from $500.0 million to $575.0 million. As of the date of this Quarterly Report, there were no borrowings outstanding and $0.3 million in letters of credit outstanding, resulting in availability of $574.7 million.

As of September 30, 2015, letters of credit outstanding under the Revolving Credit Agreement had a weighted average interest rate of 1.77%.

Covenant Compliance

The Revolving Credit Agreement and the indenture governing the 7.500% senior notes due 2022 (the “Notes”) restrict our ability and the ability of certain of our subsidiaries to, among other things: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default or event of default (as defined in the indenture) has occurred and is continuing, many of the foregoing covenants pertaining to the Notes will be suspended. If the ratings on the Notes were to decline subsequently to below investment grade, the suspended covenants would be reinstated.

As of September 30, 2015, the Company was in compliance with all required covenants under the Revolving Credit Agreement and the indenture governing the Notes.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

Principal Maturities of Long-Term Debt

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

 

Interest Expense

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

 

 

 

NOTE 8.    EQUITY

Earnings Per Share

Basic earnings per share (“EPS”) measures the performance of an entity over the reporting period.  Diluted earnings per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B common stock, par value $0.01 per share (“Class B Common Stock”) and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and restricted stock units. For the three months ended September 30, 2015, Class B Common Stock was not recognized in dilutive earnings per share calculations as it would be antidilutive, but unvested restricted stock and restricted stock unit awards were recognized as they would be dilutive upon vesting.  For the three months ended September 30, 2014, Class B Common Stock, unvested restricted stock and restricted stock unit awards are recognized as they would be dilutive.  For the nine months ended September 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

September 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:

 

 

Noncontrolling Interest

Upon completion of the September Offering, the Company’s ownership of Parsley LLC increased to 79.4%, with the PE Unit Holders’ ownership of Parsley LLC decreasing to 20.6%.  The Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the PE Unit Holders as a noncontrolling interest.  The Company has also consolidated the financial position and results of operations of Pacesetter due to Operations’ 63% ownership interest.  The remaining 37% interest retained by Pacesetter’s President is reflected 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 the carrying value of the noncontrolling interest be adjusted to reflect the change in the Company’s interest, in addition, any difference between the fair value of the consideration received and the amount by which the noncontrolling interest is adjusted is recognized directly in equity attributable to the Company.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

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

 

 

NOTE 9.    STOCK BASED COMPENSATION

In connection with the Company’s initial public offering (the “Offering”) in May 2014, the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan for employees, consultants, and directors of the Company who perform services for the Company.  Refer to “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.

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, and performance unit activity for the nine months ended September 30, 2015:

 

Stock based compensation expense related to restricted stock, restricted stock units, and performance units was $2.1 million and $0.9 million for the three months ended September 30, 2015 and 2014, respectively.  Stock based compensation expense related to restricted stock, restricted stock units, and performance units was $5.9 million and $1.2 million for the nine months ended September 30, 2015 and 2014, respectively.  There was approximately $18.9 million of unamortized compensation expense relating to outstanding restricted stock, restricted stock units, and performance units at September 30, 2015.  Stock based compensation also includes the $51.1 million one-time stock based compensation expense related to the incentive unit compensation recognized upon the Corporate Reorganization for the nine months ended September 30, 2014.

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

NOTE 10.    INCOME TAXES

Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to United States (“U.S.”) federal income tax. The Company is a corporation and it is subject to U.S. federal income tax. The tax implications of the Offering and the Company’s concurrent corporate reorganization, and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying condensed consolidated and combined financial statements. The effective combined U.S. federal and state income tax rate as of September 30, 2015 was 24.3%.  During the three months ended September 30, 2015 and 2014, the Company recognized an income tax expense of $0.6 million and $9.4 million, respectively. During the nine months ended September 30, 2015 and 2014, the Company recognized an income tax benefit of $15.1 million and an income tax expense of $11.7 million, respectively. Total income tax expense for the three and nine months ended September 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 (loss) attributable to noncontrolling ownership interests.

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.

As a result of the September Offering, 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 2.2% 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 $4.9 million during the three months ended September 30, 2015. 

NOTE 11.    RELATED PARTY TRANSACTIONS

Well Operations

During the three and nine months ended September 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 September 30, 2015 and 2014, totaled $1.1 million and $3.3 million, respectively. The revenues disbursed to such Related Party Working Interest Owners for the nine months ended September 30, 2015 and 2014, totaled $3.3 million and $10.3 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, respectively, 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 September 30, 2015 and 2014, the Company incurred charges totaling $1.0 million and $1.1 million, respectively, for services performed by SPS for the Company’s well operations and drilling activities.  During the nine months ended September 30, 2015 and 2014, the Company incurred charges totaling $3.6 million and $2.9 million, respectively, for services performed by SPS for the Company’s well operations and drilling activities.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

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 nine months ended September 30, 2015, the Company incurred charges totaling $0.9 million and $3.0 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 nine months ended September 30, 2014.

Davis, Gerald, and Cremer, PC

During the three months ended September 30, 2014, we incurred charges totaling $0.1 million for legal services from Davis, Gerald & Cremer, PC, of which our director David H. Smith is a shareholder.  There were no such charges incurred during the three months ended September 30, 2015. During the nine months ended September 30, 2015 and 2014, we incurred charges totaling $0.2 million and $0.2 million, respectively, for legal services from Davis, Gerald & Cremer, PC.

Exchange Right

In accordance with the terms of Parsley LLC’s first amended and restated limited liability company agreement, the PE Unit Holders generally have the right to exchange (the “Exchange Right”) their PE Units (and a corresponding number of shares of the 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 (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 nine months ended September 30, 2015 and 2014, each of the following purchasers accounted for more than 10% of the Company’s revenue:  

 

 

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

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

 

 

NOTE 13.    DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS

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

 

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 September 30, 2015, was approximately $533.5 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

September 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

 

Ninth Amendment to the Revolving Credit Agreement

On November 3, 2015, the Company entered into the Ninth Amendment to the Revolving Credit Agreement (the “Ninth Amendment”).  The Ninth Amendment increases the Aggregate Elected Borrowing Base Commitments from $500.0 million to $575.0 million and increases the Borrowing Base from $500.0 million to $575.0 million.  In addition, the Ninth Amendment provides for a limited waiver of certain restrictions on divestitures by the Company contained in the Revolving Credit Agreement to permit the Company to divest certain producing properties and undeveloped acreage located in Dawson and Martin Counties, provided that the disposition occurs on or before December 31, 2015.

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PARSLEY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

September 30, 2015

(Unaudited)

 

Divestitures

The Company entered into an agreement to divest approximately 7,300 net acres in north Martin and south Dawson Counties, with approximately 500 Boe/d of associated net production, for $40.0 million in cash, subject to customary closing conditions and adjustments.  The transaction is anticipated to close during the fourth quarter of 2015.

 

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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 Energy, LLC (“Parsley LLC”) and its predecessors, Parsley Energy Operations, LLC (“Operations”) and Parsley Energy, L.P. (“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 and development of unconventional oil and natural gas reserves located 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 and development 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 September 30, 2015, our acreage position was 176,115 gross (125,543 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 September 30, 2015, we operated approximately 701 vertical wells across our acreage in the Midland Basin. Since commencing our horizontal drilling program in 2014 through September 30, 2015, we have drilled and completed 48 horizontal wells in the Midland Basin, of which 11 and 30 were completed during the three and nine months ended September 30, 2015, respectively. As of September 30, 2015, we operated 57 horizontal wells.  Additionally, we commenced our vertical appraisal drilling program in the Delaware Basin during the first quarter of 2014.  At September 30, 2015, we had drilled and completed three vertical appraisal wells in the Delaware Basin. As of December 31, 2014, we had 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 September 30, 2015, we had interests in 754 gross (479 net) producing wells across our properties and operated approximately 95% 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 September 30, 2015 and 2014, our revenues were derived 80% and 76%, respectively, from oil sales; 11% and 10%, respectively, from natural gas sales; and 9% and 14%, respectively, from NGLs sales. For the nine months ended September 30, 2015 and 2014, our revenues were derived 80% and 76%, respectively, from oil sales; 10% and 10%, 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 nine months ended September 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 September 30, 2015, WTI posted prices ranged from $38.24 to $56.96 per Bbl and the Henry Hub (“HH”) spot market price of natural gas ranged from $2.52 to $2.93 per MMBtu.  During the three months ended September 30, 2014, WTI posted prices ranged from $91.16 to $105.34 per Bbl and the HH spot market price of natural gas ranged from $3.75 to $4.46 per MMBtu.  During the nine months ended September 30, 2015, WTI posted prices ranged from $38.24 to $61.43 per Bbl and the HH spot market price of natural gas ranged from $2.49 to $3.23 per MMBtu.  During the nine months ended September 30, 2014, WTI posted prices ranged from $91.16 to $107.26 per Bbl and the HH spot market price of natural gas ranged from $3.75 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 September 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 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.

On February 5, 2015, we entered into an agreement to sell 14,885,797 shares of our Class A common stock, par value $0.01 per share (“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 us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $224.0 million.

On September 18, 2015, we entered into an agreement to sell 14,950,000 shares of our Class A Common Stock (including 1,950,000 shares issued pursuant to the underwriters’ option to purchase additional shares) at a price of $15.00 per share in an underwritten public offering. The September Offering resulted in gross proceeds of approximately $224.3 million to us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $217.0 million. A portion of the net proceeds were used to repay borrowings outstanding under our amended and restated credit agreement (as amended, the “Revolving Credit Agreement”) with Wells Fargo Bank, National Association, as the administrative agent, and the remainder of the net proceeds are expected to be used to fund a portion of our capital program, which may include acquisitions.

Stock Based Compensation

Stock based compensation includes amortization expense related to grants from our 2014 Long Term Incentive Plan.  Refer to Note 9—Stock-Based Compensation to our condensed consolidated and combined financial statements included elsewhere in this Quarterly Report for additional discussion.  Stock based compensation also includes the $51.1 million one-time stock based compensation expense related to the incentive unit compensation recognized upon the Corporate Reorganization.

Public Company Expenses

We 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.

Impairment of Oil and Gas Properties

We perform assessments of long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable.  The cash flow model we use to assess proved properties for impairment includes numerous assumptions.  The primary factors that may affect estimates of future cash flow are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves (ii) results of future drilling activities, (iii) management’s price outlook and (iv) increases or decreases in production costs and capital costs associated with producing our reserves.  All inputs to the cash flow model must be evaluated at each measurement date.

Our estimates of undiscounted future net cash flows attributable to oil and gas properties on September 30, 2015 indicated that their carrying amounts were expected to be recovered, but continue to be at risk for impairment if estimates of future cash flows decline. It is reasonably possible that management’s price outlook could decline further during 2015, which may reduce our estimate of undiscounted future net cash flows resulting in additional impairment charges to oil and gas properties

Income Taxes

Our accounting predecessors are limited liability companies or limited partnerships and therefore not subject to 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

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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.

Our operations located in Texas are subject to an entity-level tax, the Texas margin tax, at a statutory rate of up to 0.75% of Texas taxable margin.

Drilling Activity

As of September 30, 2015, we operated four horizontal drilling rigs on our properties. For the nine months ended September 30, 2015, our capital expenditures for drilling and completions were $317.0 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 September 30, 2015 Compared to Three Months Ended September 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 sales decreased 18% to $51.7 million during the three months ended September 30, 2015 from $63.3 million during the three months ended September 30, 2014. The decrease is attributable to a $41.61 per barrel decrease in average oil prices for the three months ended September 30, 2015, which is offset by an increase in volumes sold of 420 MBbls of oil. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $36.3 million while decreases in oil prices accounted for a negative change of $47.9 million.

Natural gas sales decreased by 15% to $7.1 million during the three months ended September 30, 2015 from $8.3 million during the three months ended September 30, 2014. The revenue decrease is a result of a $1.33 per Mcf decrease in our average realized natural gas prices for the three months ended September 30, 2015, which was partially offset by an increase in volumes sold of 566 MMcf. Of the overall changes in natural gas sales, increases in natural gas production volumes accounted for a positive change of $2.3 million while the decrease in natural gas prices account for a negative change of $3.5 million.

NGLs sales decreased by 54% to $5.5 million during the three months ended September 30, 2015 from $12.0 million during the three months ended September 30, 2014.  The decrease is attributable to a $21.95 per Boe decrease in average NGLs price, which was partially offset by an increase in volumes sold of 60 Boe.  Of the overall change in NGLs, production volumes accounted for a positive change of $2.2 million while the decreases in NGLs price accounted for a negative change of $8.6 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 44% to $15.1 million during the three months ended September 30, 2015 from $10.5 million during the three months ended September 30, 2014. The increase is primarily due to the higher operated well count in the three months ended September 30, 2015 as compared to the three months ended September 30, 2014. On a per Boe basis, lease operating expenses increased to $7.63 per Boe from $7.45 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 37% to $3.5 million during the three months ended September 30, 2015 from $5.5 million during the three months ended September 30, 2014 due to decreased revenue resulting from decreased average prices.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased by $25.7 million to $46.1 million or $23.23 per Boe for the three months ended September 30, 2015 from $20.4 million or $14.45 per Boe during the three months ended September 30, 2014 due to an increase in capitalized costs and production volumes.

General and Administrative Expenses. General and administrative expenses increased 42% to $14.0 million during the three months ended September 30, 2015 from $9.9 million during the three months ended September 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 increased professional fees incurred in conjunction with operating as a public company.

Exploration Costs. Exploration costs of $3.8 million during the three months ended September 30, 2015 are comprised of approximately $2.7 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 $0.8 million of impairment expense related to exploratory wells and approximately $0.3 million of non-cash leasehold amortization expense directly related to unproved leasehold costs. No exploration costs were incurred during the three months ended September 30, 2014.

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Acquisition Costs.  Acquisition costs of $2.5 million during the three months ended September 30, 2014 are due to a one-time advisory and valuation fee related to an acquisition of oil and gas properties.  There was no such fee incurred during the three months ended September 30, 2015.

Stock Based Compensation. Stock based compensation increased $1.2 million to $2.1 million for the three months ended September 30, 2015 from $0.9 million for the three months ended September 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 September 30, 2015. The increase in stock based compensation is due to additional restricted stock, restricted stock units, and performance units being issued subsequent to September 30, 2014.

Other Operating Expenses.  During the three months ended September 30, 2015, other operating expenses were approximately $0.2 million, which are related to operating expenses incurred during the normal course of business of Pacesetter Drilling, LLC (“Pacesetter”), our majority owned subsidiary.  There were no such expenses incurred during the three months ended September 30, 2014, as Pacesetter was not formed until April 2015.

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

 

* Not meaningful 

Interest Expense, net. Interest expense increased 10% to $11.0 million in the three months ended September 30, 2015 from $10.0 million during the three months ended September 30, 2014 primarily due to having an outstanding balance on the Revolving Credit Agreement for most of the three months ended September 30, 2015.  This results in the weighted average outstanding debt being greater during the three months ended September 30, 2015 as compared to the three months ended September 30, 2014.

Derivative Income. Derivative income increased $22.5 million to $34.3 million during the three months ended September 30, 2015, compared to a $11.8 million during the three months ended September 30, 2014 primarily as a result of the favorable commodity price changes for derivatives but unfavorable commodity price changes for operations on increased hedging activities.

Other Income (Expense). Other income (expense) decreased $0.7 million to an expense of $0.6 million during the three months ended September 30, 2015 from income of $0.2 million during the three months ended September 30, 2014.  The decrease is largely attributable to a $1.0 million decrease related to income from equity investments during the three months ended September 30, 2015 from the three months ended September 30, 2014. This decrease is offset by $0.2 million of license fee income, which is related to licensing of certain geological and geophysical seismic data and an increase of approximately $0.1 million of other miscellaneous business related expenses.

Income Tax Expense

The effective combined U.S. federal and state income tax rate as of September 30, 2015 was 24.3%. During the three months ended September 30, 2015, we recognized a tax expense of $0.6 million, a decrease of $8.8 million as compared to the $9.4 million tax expense we recognized during the three months ended September 30, 2014. The decrease was attributable to the corresponding decrease in net income during the applicable periods.

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Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 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 sales decreased by 7% to $158.8 million during the nine months ended September 30, 2015 from $170.9 million during the nine months ended September 30, 2014. The decrease is attributable to a $43.54 per barrel decrease in average oil prices for the nine months ended September 30, 2015, which is offset by the increase in volumes sold of 1,467 MBbls of oil. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $133.5 million while decreases in oil price accounted for a negative change of $145.6 million. Our production volumes increased due to increased drilling activities and acquisitions during the period between the quarters.

Natural gas sales decreased by 10% to $20.7 million during the nine months ended September 30, 2015 from $23.1 million during the nine months ended September 30, 2014. The revenue decrease is a result of a $1.80 per Mcf decrease in our average realized natural gas prices for the nine months ended September 30, 2015, which was partially offset by an increase in volumes sold of 2,530 MMcf. Of the overall changes in natural gas sales, increases in natural gas production volumes accounted for a positive change of $11.4 million while the change in natural gas price account for a negative change of $13.7 million.

NGLs sales decreased by 40% to $17.8 million during the nine months ended September 30, 2015 from $29.7 million during the nine months ended September 30, 2014.  The decrease is attributable to a $21.73 per Boe decrease in average NGLs price, which was partially offset by an increase in volumes sold of 314 Boe.  Of the overall change in NGLs, increases in NGLs production volumes accounted for a positive change of $11.9 million while the decrease in NGLs price accounted for a negative change of $23.8 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 $22.8 million to $50.0 million during the nine months ended September 30, 2015 from $27.2 million during the nine months ended September 30, 2014. The increase is primarily due to the higher operated well count in the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014. On a per Boe basis, lease operating expenses increased to $8.75 per Boe from $7.75 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 decreased 4% to $13.4 million during the nine months ended September 30, 2015 from $14.0 million during the nine months ended September 30, 2014 due to a decrease in production taxes, which is attributable to the decreased pricing.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $68.7 million to $127.9 million or $22.39 per Boe for the nine months ended September 30, 2015 from $59.2 million or $16.87 per Boe during the nine months ended September 30, 2014 due to an increase in capitalized costs and production volumes.

General and Administrative Expenses. General and administrative expenses increased 54% to $38.1 million during the nine months ended September 30, 2015 from $24.8 million during the nine months ended September 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 increased production in addition to professional fees associated with being a public company.

Exploration Costs. Exploration costs of $8.6 million during the nine months ended September 30, 2015 are comprised of approximately $2.1 million of non-cash leasehold impairment expense directly related to future leasehold expirations and unproved leasehold amortization and approximately $0.8 million of impairment expense related to exploratory wells.  Exploration costs also include approximately $5.7 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 nine months ended September 30, 2014.

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Acquisition Costs.  Acquisition costs of $2.5 million during the nine months ended September 30, 2014 are due to a one-time advisory and valuation fee related to an acquisition of oil and gas properties.  There was no such fee incurred during the nine months ended September 30, 2015.

Stock Based Compensation. Stock based compensation decreased $46.4 million to $5.9 million for the nine months ended September 30, 2015 from $52.3 million for the nine months ended September 30, 2014.  The decrease is almost entirely attributable to a one-time stock based compensation expense related to incentive unit compensation of $51.1 million that was recognized upon the Corporate Reorganization during the nine months ended September 30, 2014.  This decrease is offset by a $4.7 million increase in stock based compensation related to our long term incentive plan, pursuant to which additional restricted stock, restricted stock units, and performance units were issued subsequent to September 30, 2014.  

Rig Termination.  During the nine months ended September 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 nine months ended September 30, 2014.

Other Operating Expenses.  During the nine months ended September 30, 2015, other operating expenses were approximately $0.3 million, which are related to operating expenses incurred during the normal course of business of Pacesetter.  There were no such expenses incurred during the nine months ended September 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 19% to $33.2 million in the nine months ended September 30, 2015 from $27.8 million during the nine months ended September 30, 2014 primarily due to accrued interest related to the Notes, of which only $400 million were outstanding for a portion of the nine months ended September 30, 2014 as compared to $550 million outstanding during the nine months ended September 30, 2015.

Prepayment Premium on Extinguishment of Debt.  During the nine months ended September 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 nine months ended September 30, 2015.

 

Derivative Income. Gain on derivative instruments increased $32.0 million to $23.7 million during the nine months ended September 30, 2015 from a loss of $8.3 million during the nine months ended September 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. Other income increased by $0.8 million to income of $1.3 million during the nine months ended September 30, 2015 from $0.4 million during the nine months ended September 30, 2014.  The increase is attributable to $1.2 million of license fee income earned during the nine months ended September 30, 2015.  In addition, income from equity investments increased approximately $0.1 million during the nine months ended September 30, 2015 from the nine months ended September 30, 2014, which is offset by a decrease in other miscellaneous income of approximately $0.5 million.

Income Tax Benefit (Expense)

The effective combined U.S. federal and state income tax rate as of September 30, 2015 was 24.3%.  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

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through May 29, 2014.  During the nine months ended September 30, 2015, we recognized a tax benefit of $15.1 million, a decrease in tax expense of $26.8 million as compared to the $11.7 million tax expense we recognized during the nine months ended September 30, 2014. The decrease was attributable to the corresponding decrease in net income during the applicable periods.  During the nine months ended September 30, 2015, we were subject to the federal income tax rate for the entire period as compared to only four months during the nine months ended September 30, 2014.

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 Revolving Credit Agreement.  On November 3, 2015, in connection with the semi-annual redetermination of our “Borrowing Base” (as defined in the Revolving Credit Agreement), the Borrowing Base under our Revolving Credit Agreement was increased to $575.0 million from $500.0 million. 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 $552.2 million and $672.1 million as of September 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 nine months ended September 30, 2015, our aggregate drilling and completion capital expenditures were $317.0 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.  The majority 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.

To fund a portion of our capital requirements for the nine months ended September 30, 2015, we issued shares of our Class A Common Stock in connection with the Private Placement and the September Offering. During the nine months ended September 30, 2015, we received aggregate net proceeds of $441.0 million from the Private Placement and the September Offering, and made aggregate net debt payments in excess of borrowings of $120.5 million.

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, together with a portion of the net proceeds from the September Offering, 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 make assurances 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.

 

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Cash Flows

 

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

 

Cash Flow Provided by Operating Activities. Net cash provided by operating activities was approximately $110.5 million and $74.1 million for the nine months ended September 30, 2015 and 2014, respectively. Net cash provided by operating activities increased $36.4 million from the period ending September 30, 2014 to September 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 29% 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 $357.5 million and $935.3 million for the nine months ended September 30, 2015 and 2014, respectively. The decreased amount of cash used in investing activities during the nine months ended September 30, 2015, as compared to the nine months ended September 30, 2014, was due primarily to the $557.6 million decrease in acquisitions of oil and natural gas properties during the nine months ended September 30, 2015 over the nine months ended September 30, 2014.

Cash Flow Provided by Financing Activities.  Net cash provided by financing activities was approximately $319.6 million and $974.6 million for the nine months ended September 30, 2015 and 2014, respectively. Net cash provided by financing activities decreased during the period ending September 30, 2015 from the period ending September 30, 2014 due to net proceeds from our initial public offering of $867.8 million and net debt borrowings in excess of payments of $125.7 million during the nine months ended September 30, 2014. During the nine months ended September 30, 2015, we received aggregate net proceeds of $441.0 million from the Private Placement and the September Offering of our Class A Common Stock and made aggregate net debt payments in excess of borrowings of $120.5 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 $(1.3) million and $(16.7) million at September 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 $123.1 million and $50.6 million at September 30, 2015 and December 31, 2014, respectively. The $72.5 million increase in cash is primarily attributable to net proceeds of $217.0 million received as a result of the September Offering offset by cash disbursements related to payments on the Revolving Credit Agreement, acquisitions, and other operating expenses.  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.

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Critical Accounting Policies and Estimates

There have not been any material changes during the three months ended September 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 our critical accounting policies.

Off-Balance Sheet Arrangements

As of September 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.  We also use basis swap contracts to mitigate basis risk caused by the volatility of our 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 September 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 September 30, 2015, the fair market value of our oil derivative contracts was a net asset of $72.8 million.  Based on our open oil derivative positions at September 30, 2015, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $19.5 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $23.9 million.  As of September 30, 2015, the fair market value of our natural gas derivative contracts was a net asset of $0.4 million.  Based upon our open commodity derivative positions at September 30, 2015, a 10% increase or decrease in the NYMEX HH price would have an immaterial impact on the value of the positions.

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. As of September 30, 2015, however, we had no outstanding borrowings related to our Revolving Credit Agreement, and therefore an increase in interest rates would not result in increased interest expense.

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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 September 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 September 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 September 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 and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our businesses, financial condition or future results.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or future results.  There have been no material changes in our risk factors from those described in our Annual Report or our other SEC filings.

Item 5.    Other Information

On November 3, 2015, the Company entered into the Ninth Amendment to the Revolving Credit Agreement (the “Ninth Amendment”).  The Ninth Amendment increases the Aggregate Elected Borrowing Base Commitments (as defined in the Revolving Credit Agreement) from $500.0 million to $575.0 million and increases the Borrowing Base from $500.0 million to $575.0 million.  In addition, the Ninth Amendment provides for a limited waiver of certain restrictions on divestitures by the Company contained in the Revolving Credit Agreement to permit the Company to divest certain producing properties and undeveloped acreage located in Dawson and Martin Counties, provided that the disposition occurs on or before December 31, 2015.  The foregoing description of the Ninth Amendment is not complete and is qualified by reference to the full text of the Ninth Amendment, which is filed as Exhibit 10.1 to this Quarterly Report and incorporated herein by reference.

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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