UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended September 30, 2014

or

For the transition period from             to             

Commission File Number: 001-36463            

 

PARSLEY ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

(512) 505-5100

(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 14, 2014, the registrant had 93,934,804 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, 2014

 

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 the heading “Risk Factors” included in our final prospectus dated May 22, 2014 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b) under the Securities Act, on May 27, 2014 (the “Final Prospectus”).  These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

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

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

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

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

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

 

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GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

The terms defined in this section are used throughout this Quarterly Report on Form 10-Q:

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

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

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

“British thermal unit” or “Btu.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“condensate.” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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

“dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

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

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

“exploratory well.” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

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

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

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

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

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

“lease operating expense.” All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

“LIBOR.” London Interbank Offered Rate.

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

“MBoe.” One thousand barrels of oil equivalent.

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

“MMBtu.” One million British thermal units.

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

“natural gas liquids” or “ NGLs.” The combination of ethane, propane, butane, isobutane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

“net acres” or “net wells.” The percentage of total acres or wells, as the case may be, an owner has out of a particular number of gross acres or wells. For example, an owner who has 50% interest in 100 gross acres owns 50 net acres.

“NYMEX.” The New York Mercantile Exchange.

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

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

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“proved developed reserves.” Proved reserves that can be expected to be recovered:

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

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

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

“proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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

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

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

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

“recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

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

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

“reservoir.” A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.

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

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

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

“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, 2014

(Unaudited)

 

NOTE 1.    ORGANIZATION AND NATURE OF OPERATIONS

 

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

 

Initial Public Offering

 

On May 29, 2014, the Company completed its initial public offering (the “Offering”) of 57.5 million shares of the Company’s Class A common stock, par value $0.01 per share (“Class A Common Stock”) at a price of $18.50 per share.  Approximately 7.5 million of the shares were sold by selling stockholders and the Company did not receive any proceeds from the sale of those shares.  The remaining approximately 50 million shares of the Company’s Class A Common Stock that were sold resulted in gross proceeds of approximately $924.3 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $867.8 million. The material terms of the Offering are described in the Company’s final prospectus, dated May 22, 2014 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended (the “Securities Act”), on May 27, 2014 (the “Final Prospectus”).

A portion of the proceeds from the Offering were used to repay all outstanding borrowings under the Revolving Credit Agreement (as defined herein), to make a cash payment in settlement of the Preferred Return (as defined herein), to fund the OGX Acquisition (as defined herein), and to pay fees and expenses related to the Offering.  The remaining proceeds will be used to fund a portion of the Company’s exploration and development program and for general corporate purposes.

 

Corporate Reorganization

 

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

 

Upon completion of the Offering, the Company issued and contributed 32.1 million shares of its Class B common stock, par value $0.01 per share (“Class B Common Stock”) and all of the net proceeds of the Offering to Parsley LLC in exchange for 93.2 million PE Units.  Parsley LLC distributed to each of the Existing Owners that continued to own PE Units following the Corporate Reorganization and the Offering (collectively, the “PE Unit Holders”), one share of Class B Common Stock for each PE Unit such PE Unit Holder held.  After giving effect to these transactions the Company owns an approximate 74.3% interest in Parsley LLC and Parsley LLC became a majority-owned subsidiary of the Company.  The PE Unit Holders own an approximate 25.7% interest in Parsley LLC.

 

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, (iii) Parsley Energy Operations, LLC, and its wholly-owned subsidiary, Parsley Energy Aviation, LLC, and (iv) Parsley Finance Corp.  Parsley LP owns a 50% 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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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 Final Prospectus.

 

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-month and nine-month periods ended September 30, 2014, are not necessarily indicative of the operating results of the entire fiscal year ending December 31, 2014.

 

Use of Estimates

 

These condensed consolidated and combined financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies to Parsley LLC’s annual financial statements included in the Final Prospectus describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our condensed consolidated and combined financial statements are the following:

 

 

 

 

 

 

 

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

 

Significant Accounting Policies

 

For a complete description of the Company’s significant accounting policies, see Note 3—Summary of Significant Accounting Policies in the Company’s audited financial statements in the Final Prospectus.

 

Reclassifications

 

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

 

Recent Accounting Pronouncements

 

On May 28, 2014, the FASB issued 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 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.

 

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NOTE 3.    DERIVATIVE FINANCIAL INSTRUMENTS

 

Commodity Derivative Instruments and Concentration of Risk

 

Objective and Strategy

 

The Company uses derivative financial instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its exploration and production activities. These include exchange traded and over-the-counter (OTC) crude put spread options and three way collars with the underlying contract and settlement pricings based on NYMEX West Texas Intermediate (WTI) and Henry Hub, respectively. Options and collars are used to establish a floor price, or floor and ceiling prices, for expected future oil and natural gas sales.

 

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

 

The Company uses three way collars to manage commodity price risk for both oil and natural gas production. A three way collar is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price plus the excess of the purchased put strike price over the sold put strike price.

 

As of September 30, 2014, the Company had entered into derivative contracts through December 2016 covering a total of approximately 5,925 MBbl of our projected oil production through the purchases of put spreads and three-way collars. The Company also entered into three way collars through December 2015 covering approximately 4,000 MMBtu of our projected natural gas production.

 

Derivative Activities

 

The following table summarizes the open positions for the commodity derivative instruments held by the Company at September 30, 2014:

 

 

  

 

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

 

Condensed Consolidated and Combined Balance Sheets

 

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

 

Condensed Consolidated and Combined Statements of Operation

 

The Company realized a gain from its derivative activities of $11.8 million and a loss of $5.0 million for the three months ended September 30, 2014 and 2013, respectively. Derivative losses were $8.3 million for both the nine months ended September 30, 2014 and 2013. These gains and losses are included in the Condensed Consolidated and Combined Statements of Operations line item, Derivative income (loss), as they were not designated as hedges for accounting purposes for any of the periods presented.  The fair value of the derivative instruments is discussed in Note 13—Disclosures about Fair Value of Financial Instruments.

 

Offsetting of Derivative Assets and Liabilities

 

The Company has agreements in place with all 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 nine months ended September 30, 2014 and the year ended December 31, 2013, the Company received and posted margins with some of its counterparties to collateralize certain derivative positions.

 

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

 

 

  

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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, 2014 and December 31, 2013. During the nine months ended September 30, 2014 and the year ended December 31, 2013, the Company received and posted margins with some of its counterparties to collateralize certain derivative positions.

 

NOTE 4.    PROPERTY, PLANT AND EQUIPMENT

 

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

 

 

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 (“DD&A”). Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated reservoir. Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs.  At September 30, 2014, the Company had excluded $510.2 million of capitalized costs from depletion. Depletion expense on capitalized oil and gas property was $20.0 million and $7.5 million for the three months ended September 30, 2014 and 2013, respectively.  Depletion expense on capitalized oil and gas property was $58.0 million and $15.1 million for the nine months ended September 30, 2014 and 2013, respectively. The Company had no exploratory wells in progress at September 30, 2014 and December 31, 2013.

 

The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current depletion.  Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest expense. During the three months ended September 30, 2013, the Company capitalized interest of $0.6 million.  Due to the nature of the Company’s drilling operations and the timing of payment, there was no capitalized interest during the three months ended September 30, 2014. During the nine months ended September 30, 2014 and 2013, the Company capitalized interest of $2.7 million and $1.5 million, respectively.

 

Depreciation expense on other property and equipment was $0.4 million and $0.3 million for the three months ended September 30, 2014 and 2013, respectively. Depreciation expense was $1.2 million and $0.9 million for the nine months ended September 30, 2014 and 2013, respectively.

 

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NOTE 5.    ACQUISITIONS OF OIL AND GAS PROPERTIES

 

The following acquisitions were accounted for using the acquisition method under ASC Topic 805, “Business Combinations”, which requires the acquired assets and liabilities to be recorded at fair values as of the respective acquisition dates.

 

During the three and nine months ended September 30, 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 $7.5 million and $19.8 million, respectively. The Company reflected the total consideration paid as part of its cost 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, 2014 were not material.

 

On March 27, 2014, the Company entered into a purchase and sale agreement, effective May 1, 2014, pursuant to which it agreed to acquire 2,240 gross (2,005 net) acres in its Midland Basin-Core area and seven gross (6.3 net) wells for total consideration of $165.5 million. The $165.5 million purchase price was allocated as follows: $57.3 million of proved capitalized costs, $108.4 million of unproved capitalized costs, and $0.2 million of asset retirement obligations (the “Pacer Acquisition”).

 

The following table presents operating revenues and net earnings included in the Company’s Condensed Consolidated and Combined Statements of Operations for the nine months ended September 30, 2014 as a result of the Pacer Acquisition described above.

For the three and nine months ended September 30, 2014, the following pro forma financial information represents the combined results for the Company and the properties acquired in the Pacer Acquisition as if the acquisition and the required financing had occurred on January 1, 2013. The pro forma information assumes that the Company’s revolving credit facility was used to finance the Pacer Acquisition. For the three months ended September 30, 2013, the pro forma information includes the effects of adjustments for DD&A expense of $0.5 million and the effects of incremental interest expense on acquisition financing of $1.4 million.  The three months ended September 30, 2014 do not include any adjustments due to the close of the transaction during May 2014.  For the nine months ended September 30, 2014 and 2013, the pro forma information includes the effects of adjustments for DD&A expense of $1.8 million and $0.8 million, respectively, and the effects of incremental interest expense on acquisition financing of $2.3 million and $4.1 million, respectively.

On May 30, 2014, the Company entered into the First Amendment to Option Agreement to which the Company acquired an option to purchase 4,640 gross (4,640 net) acres in its Midland Basin-Core area for total consideration of $127.7 million.  On June 4, 2014, the option was exercised.  The $127.7 million purchase price was allocated as follows: $10.9 million of proved capitalized costs, $116.9 million of unproved capitalized costs, and $0.1 million of asset retirement obligations (the “OGX Acquisition”).  The revenues and operating expenses attributable to the OGX Acquisition during the three and nine months ended September 30, 2014 were not material.

 

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On September 30, 2014, the Company entered into a purchase and sale agreement, effective September 1, 2014, pursuant to which it agreed to acquire 4,320 gross (4,228 net) acres and 9 gross (9 net) wells in its Midland Basin-Core area for total consideration of $242.0 million.  The $242.0 million purchase price was allocated as follows: $112.1 million of proved capitalized costs, $130.1 million of unproved capital costs, and  $0.2 million of asset retirement obligations (the “Cimarex Acquisition”).  The revenues and operating expenses attributable to the Cimarex Acquisition during the three and nine months ended September 30, 2014 and 2013 were not material.

 

On December 30, 2013, the Company acquired non-operated working interests in a number of wells which it currently operates for $80.0 million, including $53.6 million of proved capitalized costs, $26.0 million of unproved capitalized costs, and $0.4 million of asset retirement costs (the “Merit Acquisition”). The transaction did not increase Parsley LLC’s gross acreage position, but increased its net acreage by 637 acres in Upton County, Texas.

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

NOTE 6.    EQUITY INVESTMENT

 

The Company uses the equity method of accounting for the investment in SPS, with earnings or losses, after adjustment for intra-company profits and losses, reported in the income (loss) from equity investment line on the Condensed Consolidated and Combined Statements of Operations.

 

As of September 30, 2014 and December 31, 2013, the balance of the Company’s investment in SPS was $2.2 million and $1.8 million, respectively. The investment balance increased by $0.7 million and $0.2 million for the three months ended September 30, 2014 and 2013, respectively, and increased by $1.1 million and $0.5 million for the nine months ended September 30, 2014 and 2013, for the Company’s share of SPS’ net income, before adjustment for intra-company profits and losses, respectively. During the three and nine months ended September 30, 2014 and 2013, SPS provided services to the Company in its oil and natural gas field development operations, which the Company capitalized as part of its oil and gas properties. As such, that portion of the Company’s share of SPS’ gross profit from these services totaling $0.2 million and $0.1 million for the three months ended September 30, 2014 and 2013 and $0.7 million and $0.3 million for the nine months ended September 30, 2014 and 2013, was subsequently eliminated from its share of SPS’s net income and a corresponding reduction was made to the carrying value of its investment.

 

NOTE 7.    ASSET RETIREMENT OBLIGATIONS

 

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

 

The following table summarizes the changes in the Company’s asset retirement obligations for the nine months ended September 30, 2014 (in thousands):

 

 

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NOTE 8.    DEBT

 

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

 

 

Revolving Credit Agreement

 

On October 21, 2013, the Company entered into an amended and restated credit agreement (as amended, the “Revolving Credit Agreement”) with Wells Fargo Bank National Association as the administrative agent. The Revolving Credit Agreement provides a revolving credit facility with a borrowing capacity up to the lesser of (i) the borrowing base (as defined in the Revolving Credit Agreement) and (ii) $750.0 million. The Revolving Credit Agreement matures on September 10, 2018. The borrowing base will be redetermined by the lenders at least semi-annually on each April 1 and October 1, with the next redetermination to occur on October 1, 2014. The Revolving Credit Agreement is secured by substantially all of the Company’s assets.

 

On April 15, 2014, in connection with the issuance of the Notes (as defined herein) offering, the Company entered into the Third Amendment to the Amended and Restated Credit Agreement whereby the borrowing base was increased from $227.5 million to $365.0 million. Immediately following the Notes offering, the borrowing base was reduced to $327.5 million.

 

On May 2, 2014, the Company entered into the Fourth Amendment to the Revolving Credit Agreement whereby the expiration date of any letter of credit was increased from fifteen months to eighteen months.

 

On May 9, 2014, the Company entered into the Fifth Amendment to the Revolving Credit Agreement whereby certain terms were amended permitting the Corporate Reorganization to occur.

 

On May 29, 2014, the Company used proceeds from the Offering to repay the outstanding borrowings under the Revolving Credit Agreement.

 

On September 4, 2014, the Company entered into the Sixth Amendment to the Revolving Credit Agreement (the “Sixth Amendment”.)  The Sixth Amendment changed the reporting requirements and deliverables in response to the Company becoming a public company.

 

As of September 30, 2014, the borrowing base was $327.5 million, and in November 2014, the borrowing base was increased to $575.0 million, with a commitment level of $365.0 million.  There were no borrowings outstanding and $0.3 million in letters of credit outstanding as of September 30, 2014, resulting in availability of $327.2 million.

 

Borrowings under the Revolving Credit Agreement can be made in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBO rate (equal to the product of: (a) the LIBO rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (expressed as a decimal) on such date at which the Administrative Agent is required to maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the adjusted LIBO rate (as calculated above) plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of our borrowing base utilized. The Revolving Credit Agreement also provides for a commitment fee ranging from 0.375% to 0.500%, depending on the percentage of our borrowing base utilized. As of September 30, 2014, letters of credit outstanding under the Revolving Credit Agreement had a weighted average interest rate of 1.75%. The Company may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

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

 

 

 

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

 

At September 30, 2014, the Company was in compliance with all required covenants. The Revolving Credit Agreement is subject to customary events of default, including a change in control (as defined in the Revolving Credit Agreement). If an event of default occurs and is continuing, the Majority Lenders (as defined in the Revolving Credit Agreement) may accelerate any amounts outstanding.

 

7.5% Senior Notes due 2022

 

On February 5, 2014, Parsley LLC and Finance Corp. issued $400 million of 7.5% senior notes due 2022 (the “Notes”).  Interest is payable on the Notes semi-annually in arrears on each February 15 and August 15, commencing August 15, 2014.  These notes are guaranteed on a senior unsecured basis by all of our subsidiaries, other than Parsley LLC and Finance Corp.  The issuance of the Notes resulted in net proceeds, after discounts and offering expenses, of approximately $391.4 million, $198.5 million of which was used repay all outstanding term debt, accrued interest and a prepayment penalty under a second lien credit facility (which was terminated concurrently with such repayment) and $175.1 million of which was used to partially repay amounts outstanding, plus accrued interest, under the Revolving Credit Agreement.

 

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

 

At any time prior to February 15, 2017, the Company may redeem up to 35% of the Notes at a redemption price of 107.5% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 120 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to February 15, 2017, the Company may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after February 15, 2017, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 105.625% for the twelve-month period beginning on February 15, 2017, 103.750% for the twelve-month period beginning February 15, 2018, 101.875% for the twelve-month period beginning on February 15, 2019 and 100.00% beginning on February 15, 2020, plus accrued and unpaid interest to the redemption date.

 

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

 

Aircraft Term Loan

 

On April 2, 2013, the Company entered into a $2.8 million term loan (“Aircraft Term Loan”) in connection with the purchase of a corporate aircraft.  The Company paid the Aircraft Term Loan in full in August 2014.

 

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Capital Lease

 

During the nine months ended September 2014, the Company entered into an aggregate of $1.9 million in capital lease agreements payable (“Capital Leases”) in connection with the lease of vehicles for operations and field personnel. The Capital Leases bear interest at annual rates ranging from 5.0% to 7.0% with varying maturities between September 2015 and August 2018. The Capital Leases require monthly payments of $51,976 of principal and interest.

 

Principal maturities of long-term debt

 

Principal maturities of long-term debt outstanding at September 30, 2014 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, 2014 and 2013 (in thousands):

 

NOTE 9.    EQUITY

 

Preferred Stock

 

Pursuant to the Company’s Bylaws, the Company’s board of directors, subject to any limitations prescribed by law, may, without further stockholder approval, establish and issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50.0 million shares of preferred stock.  The Company had no shares of preferred stock outstanding at September 30, 2014.

 

Class A Common Stock

 

As a result of the Offering and the Corporate Reorganization, the Company has a total of 93.9 million shares of its Class A Common Stock outstanding as of September 30, 2014, which includes 0.8 million shares of restricted stock and restricted stock units.  Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors.  Upon liquidation, dissolution, distribution of assets or other winding up, the holders of Class A Common Stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and the liquidation preference of any of our outstanding shares of preferred stock.

 

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Class B Common Stock

 

As a result of the Corporate Reorganization, the Company has a total of 32.1 million shares of its Class B Common Stock outstanding as of September 30, 2014.  Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders.  Holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to the amendment of certain provisions of the Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law.

 

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

 

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

 

Earnings per Share

 

Basic earnings per share (“EPS”) measures the performance of an entity over the reporting period.  Diluted earnings per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and restricted stock units. Because the Company recognized a net loss for the nine months ended September 30, 2014, Class B Common Stock and unvested restricted stock and restricted stock unit awards were not recognized in dilutive earnings per share calculations for that period as they would be antidilutive.

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

 

 

LLC Interest Issuance

 

On June 11, 2013, Parsley LLC issued membership interests to NGP X US Holdings, L.P. and other investors for total consideration of $73.5 million. These interest holders were designated as “Preferred Holders” and granted certain rights in the limited liability agreement of Parsley LLC (the “Parsley LLC Agreement”). Included with these rights were (1) the right to receive a 9.5% return on their invested capital prior to any distribution to any other unit holders (the “Preferred Return”) and (2) the right to require Parsley LLC to redeem all, but not less than all, of each Preferred Holder’s interest in Parsley LLC after the seventh anniversary, but before the eighth anniversary, of the date of their investment, or if Bryan Sheffield ceased to be Parsley LLC’s Chief Executive Officer.

 

As the investment by the Preferred Holders was redeemable at their option, the Company reflected this investment outside of permanent equity, under the heading “Mezzanine Equity—Redeemable LLC Units” in Parsley LLC’s Condensed Consolidated and Combined Balance Sheet at December 31, 2013, in accordance with ASC Topic 480, “Distinguishing Liabilities from Equity”.

 

On May 29, 2014, in connection with the Corporate Reorganization, the Preferred Holders’ interests were converted to PE Units.  A portion of such PE Units were redeemed by Parsley LLC in exchange for the Preferred Return payment of approximately $6.7 million and the remainder of such PE Units were contributed to the Company in exchange for an equal number of shares of Class A Common Stock.

 

Incentive Units

 

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

 

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The incentive units were accounted for as liability-classified awards pursuant to ASC Topic 718, “Compensation—Stock Compensation,” as achievement of the payout conditions required the settlement of such awards by transferring cash to the incentive unit holder. As such, the fair value of the incentive unit was remeasured each reporting period through the date of settlement, with the percentage of such fair value recorded to compensation expense each period being equal to the percentage of the requisite explicit or implied service period that has been rendered at that date.

 

In connection with the Corporate Reorganization, all of the incentive units were immediately vested and converted into PE Units and, subsequently, a portion of such PE Units were exchanged on a one for one basis for shares of Class A Common Stock.  As a result, Parsley LLC was required to recognize, as a non-cash charge, the unrecognized cumulative incentive unit compensation expense of approximately $50.6 million on May 29, 2014, in addition to the $0.5 million recognized during the period from January 1, 2014 through May 29, 2014.  There was no incentive unit compensation recognized during the three months ended September 30, 2014 and 2013 or for the nine months ended September 30, 2013.

 

Restricted Stock and Restricted Stock Unit Awards

 

Restricted stock awards are awards of Class A Common Stock that are subject to restrictions on transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions. Restricted stock unit awards are awards of restricted stock units that are subject to restrictions on transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restriction.  Each restricted stock unit represents the right to receive one share of Class A Common Stock.  The fair value of such restricted stock and restricted stock units was determined using the weighted average closing price on the grant date and compensation expense is recorded over the applicable vesting periods.

 

The following table summarized the Company’s restricted stock and restricted stock unit award activity for the nine months ended September 30, 2014:

 

 

Stock based compensation expense related to restricted stock and restricted stock units was $0.9 and $1.2 million for the three and nine months ended September 30, 2014, respectively. There was approximately $13.0 million of unamortized compensation expense relating to outstanding restricted stock and restricted stock units at September 30, 2014.

 

Noncontrolling Interest

 

As a result of the Corporate Reorganization and the Offering, the Company acquired 74.3% of Parsley LLC, with the Existing Owners retaining ownership of 25.7% of Parsley LLC. As a result, the Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the Existing Owners as a noncontrolling interest.

 

Net income attributable to noncontrolling interest for the three and nine months ended September 30, 2014 of approximately $9.4 and $10.5 million, respectively, represents the net income of Parsley LLC attributable to the Existing Owners’ retained interest since May 29, 2014.

 

NOTE 10.    INCOME TAXES

 

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

 

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

 

Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to U.S. federal income tax. As part of the Corporate Reorganization, certain of the Existing Owners exchanged all or part of their PE Units for shares of the Company’s common stock, as discussed in Note 1 – Organization and Nature of Business. On the date of the Corporate Reorganization, a corresponding “first day” tax charge of approximately $95.5 million was recorded to establish a net deferred tax liability for differences between the tax and book basis of Parsley LLC’s assets and liabilities. In addition, the Company recorded a long term liability of $56.3 million to establish the TRA (as defined herein) and a corresponding deferred tax asset of $66.3 million.  The offset of the deferred tax liability, TRA, and deferred tax asset was recorded to additional paid-in capital.  During the three months ended September 30, 2014, as part of the tax return preparation process, adjustments were made to reduce the TRA liability by $4.9 million and to reduce the deferred tax asset by $5.8 million with the offset recorded to additional paid in capital.  As of September 30, 2014, the liability associated with the TRA was $51.4 million and the corresponding deferred tax asset was $60.5 million.

 

The Company is a corporation and it is subject to U.S. federal income tax. The tax implications of the corporate reorganization and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying consolidated financial statements. The effective combined U.S. federal and state income tax rate after the corporate reorganization was 35.7% percent.  Income tax expense was $9.4 million and $0.4 million for the three months ended September 30, 2014 and 2013, respectively.  Income tax expense was $11.7 million and $1.0 million for the nine months ended September 30, 2014 and 2013, respectively.  Total income tax expense for the three months and nine months ended September 30, 2014 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 permanent differences between book and taxable income.

 

NOTE 11.    RELATED PARTY TRANSACTIONS

 

Well Operations

 

During the three and nine months ended September 30, 2014 and 2013, several of the Company’s directors, officers, 5% stockholders, their immediate family, 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, 2014 and 2013, totaled $3.1 million and $4.6 million, respectively. Revenues disbursed for the nine months ended September 30, 2014 and 2013, total $10.0 million and $11.3 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 their ownership interest fell below 5%, which results in Tex-Isle no longer being considered a related party.  During the three and nine months ended September 30, 2013, the Company made purchases of equipment used in its drilling operations totaling $14.4 million and $44.0 million, respectively from Tex-Isle.  During the five months ended May 29, 2014, the Company made purchases of equipment used in its drilling operations totaling $25.0 million, from Tex-Isle, and capitalized these costs as part of its oil and natural gas property.

 

Spraberry Production Services LLC

 

As defined in Note 6—Equity Investment, as of September 30, 2014, the Company owns a 50% interest in SPS.  During the three months ended September 30, 2014 and 2013, the Company incurred charges totaling $1.1 million and $1.0 million, respectively, for services performed by SPS for the Company’s well operations and drilling activities; and during the nine months ended September 30, 2014 and 2013, the Company incurred charges totaling $2.9 million and $3.0 million, respectively for such services.  Diamond K owns a 50% interest in SPS.

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Exchange Right

In accordance with the terms of the amended Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange their PE Units (and a corresponding number of shares of the Company’s Class B Common Stock), for shares of the Company’s Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each PE Unit (and a corresponding share of Class B Common Stock) exchanged (subject to conversion rate adjustments for stock splits, stock dividends, and reclassifications) or cash (pursuant to the Cash Option). As a PE Unit Holder exchanges its PE Units, the Company’s interest in Parsley LLC will be correspondingly increased.

Tax Receivable Agreement

 

In connection with the Offering, on May 29, 2014, the Company entered into a Tax Receivable Agreement (the “TRA”) with Parsley LLC, and certain holders of PE Units prior to the Offering (each such person a “TRA Holder”), including certain executive officers. This agreement generally provides for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the Offering as a result of (i) any tax basis increases resulting from the contribution in connection with the Offering by such TRA Holder of all or a portion of its PE Units to the Company in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange by such TRA Holder of PE Units for shares of Class A Common Stock pursuant to the Exchange Right (or resulting from an exchange of PE Units for cash pursuant to the Cash Option) and (ii) 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, 2014 and 2013, each of the following purchasers accounted for more than 10% of our revenue:  

 

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

 

 

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:

 

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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 of these instruments.  The book value of the Company’s Revolving Credit Agreement approximates its fair value as the interest rate is variable.

 

The estimated fair value of the Company’s $550 million of Notes at September 30, 2014, was approximately $568.6 million. The fair value of the Notes is classified as a level 1 measurement as it is calculated based on market quotes.

 

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 8—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):

 

 

 

 

 

 

 

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There were no transfers in to or out of level 2 during the three and nine months ended September 30, 2014 or 2013.

 

NOTE 14.    SUBSEQUENT EVENTS

 

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

 

Revolving Credit Agreement

 

In November 2014, the Company entered into the Seventh Amendment to the Amended and Restated Credit Agreement whereby the borrowing base was increased from $327.5 million to $575.0 million, with a commitment level of $365.0 million.

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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 final prospectus dated May 22, 2014 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b) under the Securities Act, on May 27, 2014 under the heading “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. (together with its subsidiaries, 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 LLC was formed in June 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves in the Permian Basin. Concurrent with the formation of Parsley LLC, all of the interest holders in Parsley Energy, L.P. (“Parsley LP”), Parsley Energy Management, LLC (“PEM”), and Parsley Energy Operations, LLC (“PEO”) 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 32,145,296 units in Parsley LLC. We are the managing member of Parsley LLC and are responsible for all operational, management and administrative decisions of Parsley LLC, and we consolidate the financial results of Parsley LLC and its subsidiaries.

 

Overview

 

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

 

Our Properties

 

At September 30, 2014, our acreage position was 120,940 net acres. The vast majority of our acreage is located in the Midland Basin, and the majority of our identified vertical and horizontal drilling locations are located in our Midland Basin-Core area. Our Midland Basin-Core area contains areas of Andrews, Glasscock, Howard, Martin, Midland, Reagan, and Upton Counties.  From the time we began drilling operations in November 2009 through September 30, 2014, we have drilled and placed on production approximately 458 vertical wells across our acreage in the Midland Basin. In addition to our vertical drilling program in the Midland Basin, we initiated our horizontal development program with one rig during the fourth quarter of 2013 and have increased to three operated horizontal rigs as of September 30, 2014. Through September 30, 2014, we have drilled and placed on production 11 horizontal wells in the Midland Basin.  Additionally, we commenced our vertical appraisal drilling program in the Delaware Basin during the first quarter of 2014.  At September 30, 2014, we had drilled and completed two vertical appraisal wells and expect to drill a third vertical appraisal well. As of September 30, 2014, we have identified 1,862 potential horizontal drilling locations, 1,619 80- and 40-acre potential vertical drilling locations and 2,164 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, 2014, we had interests in 628 gross (353 net) producing wells across our properties and operated 99% of the wells in which we had an interest.

 

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How We Evaluate Our Operations

 

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

 

 

 

 

 

 

Sources of Our Revenues

 

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the three months ended September 30, 2014 and 2013, our revenues were derived 76% and 81%, respectively, from oil sales and 24% and 19%, respectively, from natural gas and NGLs sales. For the nine months ended September 30, 2014 and 2013, our revenues were derived 76% and 81%, respectively, from oil sales and 24% and 19%, respectively, from natural gas and 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. NGLs production and sales are included in our natural gas production and sales.

 

Production Volumes

 

The following table presents historical production volumes for our properties for the three and nine months ended September 30, 2014 and 2013.

 

 

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 organic drill-bit growth 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

 

The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the ability to transport crude oil to the Cushing, Oklahoma transport hub and the Gulf Coast refineries. Periodically, logistical and infrastructure constraints at the Cushing, Oklahoma transport hub have resulted in an oversupply of crude oil at Midland, Texas and thus lower prices for Midland WTI. These lower prices have adversely affected the prices we realize on oil sales and increased our differential to NYMEX WTI.

 

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The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds.

 

The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil and natural gas normally sells at a discount to the NYMEX WTI and the NYMEX Henry Hub price, respectively.  Because our NGLs are reported in our natural gas revenue, our differential to NYMEX Henry Hub is positive.

 

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the three months ended September 30, 2014, the NYMEX-WTI oil price ranged from a high of $105.34 per Bbl to a low of $91.16 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $4.46 per MMBtu to a low of $3.75 per MMBtu. For the nine months ended September 30, 2014, the NYMEX WTI oil price ranged from a high of $107.26 per Bbl to a low of $91.16 per Bbl, while the NYMEX Henry Hub natural gas price ranged from a high of $6.15 per MMBtu to a low of $3.75 per MMBtu.

 

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our oil production. By removing a significant portion of price volatility associated with our oil production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our derivatives contract prices are higher than market prices.

 

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.

 

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Our positions hedging production as of September 30, 2014 were as follows:

 

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:

 

Incentive Unit Compensation

For the nine months ended September 30, 2014 and the year ended December 31, 2013, within Incentive unit compensation, are amounts attributable to incentive units that, pursuant to the terms of the Parsley LLC limited liability company agreement at that date, were only entitled to a payout after a specified level of cumulative cash distributions had been received by Natural Gas Partners, through NGP X US Holdings, L.P. (collectively, “NGP”) and other investors, including all of our executive officers (the “PSP Members”). At December 31, 2013 and September 30, 2014, the incentive units were being accounted for as liability-classified awards pursuant to ASC Topic 718, “Compensation—Stock Compensation”, as achievement of the payout conditions required settlement of such awards by transferring cash to the incentive unit holder.  

As part of the transactions described below “Corporate Reorganization,” the Parsley LLC limited liability company agreement was amended. Such amendments, among other things, converted all outstanding incentive units in Parsley LLC into PE Units.  A portion of such PE Units were exchanged on a one for one basis for shares of Class A Common Stock, instead of in cash. As a result, on May 29, 2014, we accounted for the incentive unit awards as equity-classified awards pursuant to ASC Topic 718. This resulted in the recognition of $50.1 million of stock based compensation equal to the excess of the modified awards’ fair value (based on the initial offering price of $18.50) over the amount of cumulative compensation cost recognized prior to that date.

 

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Stock Based Compensation

 

Restricted stock awards are awards of Class A Common Stock that are subject to restrictions on transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions. Restricted stock unit awards are awards of restricted stock units that are subject to restrictions on transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restriction.  Each restricted stock unit represents the right to receive one share of Class A Common Stock.  The fair value of such awards was determined using the weighted average closing price on the grant date and compensation expense is recorded over the applicable vesting periods. During the three and nine months ended September 30, 2014, 31,220 and 769,694 shares of restricted stock and zero and 23,649 restricted stock units were granted to our directors, management, and employees, respectively.  During the three and nine months ended September 30, 2014, 26,792 shares were forfeited.  Stock based compensation expense related to restricted stock and restricted stock units was $0.9 and $1.2 million for the three and nine months ended September 30, 2014, respectively. There was approximately $13.0 million of unamortized stock compensation expense relating to outstanding restricted stock and restricted stock units at September 30, 2014.

 

Public Company Expenses

 

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

 

Corporate Reorganization

 

The historical condensed consolidated and combined financial statements are based on the financial statements of our accounting predecessors, Parsley LLC and its predecessors, prior to the reorganization that occurred in connection with the Offering as described in Note 1—Organization and Nature of Operations – Corporate Reorganization.  As a result, the historical condensed consolidated and combined financial data may not give you an accurate indication of what our actual results would have been if the transactions described in Note 1—Organization and Nature of Operations – Corporate Reorganization had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. In addition, we have entered into the TRA with certain members of Parsley LLC (as set forth in the TRA) (the “TRA Holders”) in connection with the Offering. This agreement generally provides for the payment by us to a TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in periods after this 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 at our or Parsley LLC’s election) and (iii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. We will retain the benefit of the remaining 15% of these cash savings.

 

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 are taxed as a corporation under the Internal Revenue Code and subject to U.S. federal income tax at a statutory rate of 35.7% of pretax earnings, and, as such, the amount of our future U.S. federal income tax will be dependent upon our future taxable income.

 

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

 

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Increased Drilling Activity

 

We began drilling operations in November 2009. As of September 30, 2014, we operate eight vertical drilling rigs and three horizontal drilling rigs on our properties. For the nine months ended September 30, 2014, our capital expenditures for drilling and completions were $309.8 million, as compared to $268.4 million for all of fiscal year 2013.  

 

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

 

Results of Operations

 

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

 

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

 

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

 

Oil revenues increased 109% from $30.4 million during the three months ended September 30, 2013 to $63.3 million during the three months ended September 30, 2014. The increase is attributable to an increase in oil production volumes of 435 MBbls in conjunction with a decrease in average oil prices to $86.42 per barrel for the three months ended September 30, 2014. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $44.3 million while decreases in oil prices accounted for a negative change of $11.3 million. Our production volumes significantly increased due to increased drilling activities and acquisitions during the period.

 

Natural gas and NGLs revenues increased by 186% from $7.1 million during the three months ended September 30, 2013 to $20.3 million during the three months ended September 30, 2014. The revenue increase is a result of an increase in volumes sold of 2,644 MMcf, which was partially offset by a slight decrease in our average realized natural gas and NGLs prices to $4.99 per Mmcf, for the three months ended September 30, 2014. Natural gas revenue includes revenue from the sale of NGLs volumes. Of the overall changes in natural gas and NGLs sales, increases in natural gas and NGLs production volumes accounted for a positive change of $13.2 million while the change in natural gas and NGLs prices account for an immaterial change.

 

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

 

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 Lease Operating Expenses. Lease operating expenses increased 233% from $3.2 million during the three months ended September 30, 2013 to $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 month period ended September 30, 2014 as compared to the prior year period. On a per Boe basis, lease operating expenses increased from $5.91 per Boe to $7.45 per Boe during this period. This increase was attributable to an increase in costs for well servicing and increased workover and water disposal activity.

 

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 177% from $2.0 million during the three months ended September 30, 2013 to $5.5 million during the three months ended September 30, 2014 due to increased wellhead revenue resulting from higher production. Our increased drilling activity led to a higher number of wells brought on production during the three months ended September 30, 2014 compared to the three months ended September 30, 2013.

 

Depreciation, Depletion and Amortization. DD&A expense increased by 163% from $7.8 million during the three months ended September 30, 2013 to $20.4 million for the three months ended September 30, 2014 due to an increase in capitalized costs and production volumes. DD&A expense per BOE decreased by $0.08 primarily due to the significant increase in total proved developed reserves and increased production volumes offset by a smaller increase in developmental costs.

 

General and Administrative Expenses. General and administrative expenses increased 168% from $3.6 million during the three months ended September 30, 2013 to $9.7 million during the three months ended September 30, 2014 general and administrative expenses increased due to higher payroll and payroll-related costs as we hired additional employees to manage our growing asset base, higher rig count and increased production.

 

Acquisition costs. Acquisition costs during the three months ended September 30, 2014 are due to a one time advisory and valuation fee related to the Cimarex Acquisition, as described in Note 5—Acquisitions of Oil and Gas Properties.

Stock based compensation. Stock based compensation increased $0.9 million for the three months ended September 30, 2014 due to the issuance and amortization of the restricted stock and restricted stock units issued during the nine months ended September 30, 2014.  No stock based compensation expenses were incurred during the three month period ended September 30, 2013.

 

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

 

Interest Expense. Interest expense increased 170% from $3.7 million during the three months ended September 30, 2013 to $10.0 million in the three months ended September 30, 2014 primarily due to accrued interest related to our Senior Notes due 2022.

 

Derivative Income (Loss). Gain on derivative instruments increased 337% from a loss of $5.0 million during the three months ended September 30, 2013 to a gain of $11.8 million during the three months ended September 30, 2014 primarily as a result of the favorable commodity price changes on increased hedging activities.

 

Income Tax Expense

 

Our operations are taxed at a combined U.S. federal and state effective tax rate of 35.7%.  As a pass-through entity, our predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S. federal income tax.  During the three months ended September 30, 2014, we recognized $9.4 million of expense, an increase of $9.0 million, or 2250%, as compared to the $0.4 million we recognized during the three months ended September 30, 2013. This increase was attributable to our status as a corporation subject to U.S. federal income tax as well as a net increase in operating income, the components of which are discussed above.

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Results of Operations

 

Nine months Ended September 30, 2014 Compared to Nine months Ended September 30, 2013

 

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:

 

 

 

 

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.

 

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Oil revenues increased 162% from $65.3 million during the nine months ended September 30, 2013 to $170.9 million during the nine months ended September 30, 2014. The increase is attributable to an increase in oil production volumes of 1,177 MBbls offset by a decrease in average oil prices to $91.01 per barrel from $93.16 per barrel.  Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $109.6 million while decreases in oil prices accounted for a negative change of $4.0 million.

 

Natural gas and NGLs revenues increased 252% from $15.0 million during the nine months ended September 30, 2013 to $52.7 million during the nine months ended September 30, 2014. The revenue increase is primarily a result of an increase in volumes sold of 6,545 MMcf in conjunction with an increase in average natural gas prices to $5.39 per Mcf from $4.63 per Mcf. Of the overall changes in natural gas and NGLs, increases in natural gas and NGLs production volumes accounted for a positive change of $30.3 million while increases in prices accounted for a positive change of $7.4 million. Natural gas revenue includes revenue from the sale of NGLs volumes.

 

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

 

 

Lease Operating Expenses. Lease operating expenses increased 165% from $10.3 million during the nine months ended September 30, 2013 to $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 month period ended September 30, 2014 as compared to the prior year period. On a per Boe basis, lease operating expenses decreased from $8.28 per Boe to $7.75 per Boe. This decrease was attributable to higher initial production from new wells which lower our average price, partially offset by an increase in costs for workovers, repairs and maintenance, and additional lease operators.

 

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 232% from $4.2 million during the nine months ended September 30, 2013 to $14.0 million during the nine months ended September 30, 2014 due to increased wellhead revenue resulting from higher production. Our increased drilling activity led to a higher number of wells brought on production during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.

 

Depreciation, Depletion and Amortization. DD&A expense increased by 269% from $16.0 million during the nine months ended September 30, 2013 to $59.2 million for the nine months ended September 30, 2014 due to an increase in capitalized costs and production volumes. DD&A expense per BOE for the nine months ended September 30, 2014 increased by $3.93 from the nine months ended September 30, 2013 primarily due to the multiple oil and gas acquisitions and the increase in developmental costs.

 

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General and Administrative Expenses. General and administrative expenses increased 210% from $7.8 million during the nine months ended September 30, 2013 to $24.3 million during the nine months ended September 30, 2014 primarily due to higher payroll and payroll-related costs as we added additional employees to manage our growing asset base, higher rig count and increased production.

 

Acquisition costs. Acquisition costs during the nine months ended September 30, 2014 are due to a one time advisory and valuation fee related to the Cimarex Acquisition, as described in Note 5—Acquisitions of Oil and Gas Properties.

 

Incentive unit compensation. Incentive unit compensation increased $51.1 million during the nine months ended September 30, 2014 due to the one time incentive unit compensation expense recognized upon the Corporate Reorganization. No incentive unit compensation expenses were incurred during the nine months ended September 30, 2013.

 

Stock based compensation. Stock based compensation increased $1.2 million for the nine months ended September 30, 2014 due to the issuance and amortization of the restricted stock and restricted stock units issued during the nine months ended September 30, 2014.  No stock based compensation expenses were incurred during the nine months ended September 30, 2013.

 

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

 

 

Interest Expense. Interest expense increased 202% from $9.2 million during the nine months ended September 30, 2013 to $27.8 million in the nine months ended September 30, 2014 primarily due to higher weighted-average outstanding borrowings under our credit facilities and accrued interest under our Senior Notes due 2022.

 

Prepayment Premium on Extinguishment of Debt. During the first quarter of 2014, we incurred a $5.1 million charge related to a premium penalty on our then outstanding second lien term loan.

 

Derivative Loss. Loss on derivative instruments decreased $0.1 million during the nine months ended September 30, 2014 primarily as a result of the impact of favorable commodity price changes on increased hedging activities.

 

Income Tax Expense

 

From the date of the corporate reorganization, our operations are taxed at a combined U.S. federal and state effective tax rate of 35.7%.  As a pass-through entity, our predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S. federal income tax.  During the nine months ended September 30, 2014, we recognized $11.7 million of expense, an increase of $10.7 million, or 1070%, as compared to the $1.0 million we recognized during the nine months ended September 30, 2013. This increase was attributable to our status as a corporation subject to U.S. federal income tax as well as a net increase in operating income, the components of which are discussed above.

 

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Liquidity and Capital Resources

 

We expect that our primary sources of liquidity and capital resources will be cash flows generated by operating activities and borrowings under our Revolving Credit Agreement. Depending upon market conditions and other factors, we may also have the ability to issue additional equity and debt if needed. A portion of the net proceeds, of approximately $867.8 million, from the Offering were used to make a cash payment in settlement of the Preferred Return and to reduce amounts drawn under our Revolving Credit Agreement.  Remaining net proceeds are being used to fund a portion of our exploration and development program.

 

Our primary use of capital is for the development and exploration of oil and natural gas properties and increasing our acreage position. Our borrowings were approximately $557.4 million and $430.2 million as of September 30, 2014 and December 31, 2013, 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, 2014, our aggregate drilling and completion capital expenditures were $309.8 million. During the year ended December 31, 2013, our aggregate drilling and completion capital expenditures were $268.4 million.  These capital expenditure totals exclude acquisitions.  Substantially all of our remaining capital expenditures in 2014 for drilling and completion will be spent in the Midland Basin.

However, the amount and timing of our remaining 2014 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2014 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners.

 

Based upon current oil and natural gas price expectations for the remainder of 2014 and fiscal year 2015, we believe that our cash flow from operations, proceeds of our Offering and borrowings under our Revolving Credit Agreement will be sufficient to fund our operations through 2015. 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, 2013 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 2014 does not allocate any amounts for acquisitions of leasehold interests and proved properties. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

 

Cash Flows

 

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

 

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Cash Flow Provided by Operating Activities.  Net cash provided by operating activities was approximately $74.1 million and $31.3 million for the nine months ended September 30, 2014 and 2013, respectively. Net cash provided by operating activities increased from the period ending September 30, 2013 to September 30, 2014 primarily due to the $53.0 million increase in operating income excluding the $51.1 million non-cash incentive unit compensation.  The increase in operating income is primarily due to an increase in our production margin attributable to a 183% increase in our production volumes, which is offset by a $1.01, or 2%, decrease in average realized prices per BOE, without realized derivatives, in addition to increased expenses as a result of having more producing wells in the first nine months of 2014 as compared to the first nine months in 2013.  Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production volumes. Our production volumes in the future will in large part be dependent upon the dollar amount and results of future capital expenditures. Future levels of capital expenditures made by us may vary due to many factors, including drilling results, oil and natural gas prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.

 

Cash Flow Used in Investing Activities.  Net cash used in investing activities was approximately $935.3 million and $190.8 million for the nine months ended September 30, 2014 and 2013, respectively. The increased amount of cash used in investing activities in the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013 was due primarily to the $597.2 million increase in acquisition activity as discussed in Note 5—Acquisition of Oil and Gas Properties.  In addition, the increase is also due to additional rigs operating, our horizontal drilling plan, and drilling higher working interest wells during the nine months ended September 30, 2014 over the nine months ended September 30, 2013.

 

Cash Flow Provided by Financing Activities.  Net cash provided by financing activities was approximately $974.6 million and $164.6 million for the nine months ended September 30, 2014 and 2013, respectively. Net cash provided by financing activities increased in the period ending September 30, 2014 primarily due to the issuance of Class A Common Stock in conjunction with the Offering and Corporate Reorganization and the increase in long-term borrowings.

 

Revolving Credit Agreement. The borrowing base will be redetermined by the lenders at least semi-annually on each April 1 and October 1, with the most recent redetermination on October 1, 2014. As of September 30, 2014, the borrowing base was $327.5 million and in November 2014, the borrowing base was increased to $575.0 million, with a commitment level of $365.0 million.  There were no borrowings outstanding and $0.3 million in letters of credit outstanding as of September 30, 2014, resulting in availability of $327.2 million.

Our Revolving Credit Agreement is secured by liens on substantially all of our properties and guarantees from our subsidiaries. The Revolving Credit Agreement contains restrictive covenants that may limit our ability to, among other things:

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

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

At September 30, 2014, the Company was in compliance with all required covenants.

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Senior Unsecured Notes. See Note 8—Debt to our Condensed Consolidated and Combined Financial Statements included elsewhere in this Quarterly Report on Form 10-Q for a description of our 7.500% Senior Notes due 2022.

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 $32.2 million and $(54.2) million at September 30, 2014 and December 31, 2013, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $132.8 million and $19.4 million at September 30, 2014 and December 31, 2013, respectively. The $113.4 million increase in cash is primarily attributable to the receipt of proceeds for the sale of Class A Common Stock in conjunction with the Offering offset by acquisitions of oil and gas properties, as described in Note 5—Acquisitions of Oil and Gas Properties.  Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our credit agreement will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

 

Critical Accounting Policies and Estimates

 

The discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated and combined financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our condensed consolidated and combined financial statements. See below for an expanded discussion of our significant accounting policies and estimates made by management.

 

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

 

Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.

 

The provision for DD&A of oil and natural gas properties is calculated on a reservoir basis using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.

 

On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

 

Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

 

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as impairment expense in our Condensed Consolidated and Combined Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

 

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For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

 

Future Development Costs

 

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development costs on an annual basis.

Asset Retirement Obligations

 

We have significant obligations to remove tangible equipment and facilities associated with our oil and natural gas wells and our gathering systems, and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are associated with plugging and abandoning wells and our gathering systems. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

 

Allocation of Purchase Price in Business Combinations

 

As part of our business strategy, we periodically pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

 

Off-Balance Sheet Arrangements

 

As of September 30, 2014, 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 and natural gas 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.  For a description of our open positions at September 30, 2014, see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—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, 2014, the fair market value of our oil derivative contracts was a net asset of $27.6 million.  Based on our open oil derivative positions at September 30, 2014, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $13.6 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $22.3 million.  As of September 30, 2014, the fair market value of our natural gas derivative contracts was a net asset of $1.6 million.  Based upon our open commodity derivative positions at September 30, 2014, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately $0.7 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas derivate asset by approximately $0.7 million.

 

Counterparty Risk

 

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

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Item 4.    Controls and Procedures

 

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2014.  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 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, 2014 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) and Rule 15d-15(f) under the Exchange Act) during the three months ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

Item 5.    Other Information

 

On November 10, 2014, the Company, Wells Fargo Bank, National Association, as administrative agent, JPMorgan Chase Bank, N.A., as syndication agent, BMO Harris Bank, N.A., as documentation agent and the lenders party thereto entered into the Seventh Amendment to the Revolving Credit Agreement (the “Seventh Amendment”).  

The Seventh Amendment, among other things, modifies the terms of the Revolving Credit Agreement to allow the Company to select the Aggregate Elected Borrowing Base Commitments (as defined in the Seventh Amendment), so long as the Aggregate Elected Borrowing Base Commitments do not exceed the Borrowing Base (as defined in the Revolving Credit Agreement), and in each case subject to certain additional terms and conditions.  Pursuant to the Seventh Amendment, each Lender’s commitment to advance loans to the Company may not exceed such Lender’s Applicable Percentage (as defined in the Revolving Credit Agreement) of the Aggregate Elected Borrowing Base Commitments.  The Company may from time to time reduce or increase the Aggregate Elected Borrowing Base Commitments, in each case subject to the terms and conditions set forth in the Seventh Amendment.   As a result of the foregoing, the commitment fee on unused availability under the Revolving Credit Agreement will be based on the unused amount of the least of (i) the Aggregate Maximum Credit Amount (as defined in the Revolving Credit Agreement), (ii) the Borrowing Base and (iii) the Aggregate Elected Borrowing Base Commitments.  As of the Seventh Amendment Effective Date (as defined in the Seventh Amendment), the Aggregate Elected Borrowing Base Commitments equal $365 million.

In addition, the Seventh Amendment increases the Borrowing Base from $327.5 million to $575 million.  Notwithstanding such increase, pursuant to the foregoing paragraph and the terms of the Seventh Amendment, the maximum amount available to be drawn under the Revolving Credit Agreement as of the Seventh Amendment Effective Date is $365 million.  

From time to time, the agents, arrangers, book runners and lenders under the Revolving Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions.

The foregoing description of the Seventh Amendment is not complete and is qualified by reference to the full text of the Seventh Amendment, which is attached hereto as Exhibit 10.3 and incorporated herein by reference.

 

 

 

 

 

 

 

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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 on Form 10-Q, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” included in our final prospectus dated May 22, 2014 and filed with the SEC pursuant to Rule 424(b) under the Securities Act, on May 27, 2014 (the “Final Prospectus”), 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 has been no material changes in our risk factors from those described in the Final Prospectus.  

 

Item 6.    Exhibits

 

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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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