S-1 1 d644323ds1.htm FORM S-1 Form S-1
Table of Contents

As filed with the Securities and Exchange Commission on April 11, 2014

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Parsley Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1311  

46-4314192

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification No.)

500 W. Texas Ave., Tower I, Suite 200

Midland, Texas 79701

(432) 818-2100

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Colin W. Roberts

General Counsel

500 W. Texas Ave., Tower I, Suite 200

Midland, Texas 79701

(432) 818-2100

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

Douglas E. McWilliams

Matthew R. Pacey

Vinson & Elkins L.L.P.

1001 Fannin St., Suite 2500

Houston, Texas 77002-6760

(713) 758-2222

 

J. Michael Chambers

Keith Benson

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

 

 

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box:  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

  Proposed
Maximum
Aggregate
Offering Price(1)(2)
  Amount of
Registration Fee

Class A common stock, par value $0.01 per share

  $400,000,000   $51,520.00

 

 

(1) Includes Class A common stock issuable upon exercise of the underwriters’ option to purchase additional Class A common stock.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

 

 

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED APRIL 11, 2014

                    Shares

 

LOGO

Parsley Energy, Inc.

Class A Common Stock

 

 

This is the initial public offering of our Class A common stock. We are selling                  shares of Class A common stock and the selling shareholders are selling              shares of Class A common stock. We will not receive any proceeds from the sale of shares by the selling shareholders.

Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price of the Class A common stock is expected to be between $         and $         per share. We have applied to list our Class A common stock on the New York Stock Exchange under the symbol “PE.”

The underwriters have an option to purchase a maximum of              additional shares of Class A common stock to cover over-allotments of shares.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Prospectus Summary—Emerging Growth Company Status.”

Investing in our Class A common stock involves risks. See “Risk Factors” on page 22.

 

      

Price to

Public

    

Underwriting

Discounts and

Commissions

    

Proceeds to

Parsley
Energy, Inc.

    

Proceeds to the
Selling
Shareholders

Per Share

     $      $      $      $

Total

     $                        $                        $                        $                  

Delivery of the shares of Class A common stock will be made on or about                 , 2014.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

Credit Suisse   Goldman, Sachs & Co.
J.P. Morgan  

Wells Fargo Securities

 

Morgan Stanley

  Raymond James   Tudor, Pickering, Holt & Co.

 

RBC Capital Markets

  Global Hunter Securities
    Macquarie Capital
      Scotiabank / Howard Weil
        Simmons & Company
        International
              Stephens Inc.

The date of this prospectus is                     , 2014.


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LOGO

 

LOGO

Note: All data as of December 31, 2013, unless otherwise noted.


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     22   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     47   

USE OF PROCEEDS

     49   

DIVIDEND POLICY

     50   

CAPITALIZATION

     51   

DILUTION

     53   

SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

     55   

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     58   

BUSINESS

     80   

MANAGEMENT

     107   

EXECUTIVE COMPENSATION

     111   

CORPORATE REORGANIZATION

     124   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     129   

PRINCIPAL AND SELLING SHAREHOLDERS

     135   

DESCRIPTION OF CAPITAL STOCK

     137   

SHARES ELIGIBLE FOR FUTURE SALE

     142   

MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSEQUENCES TO NON-U.S. HOLDERS

     144   

UNDERWRITING (CONFLICTS OF INTEREST)

     148   

LEGAL MATTERS

     154   

EXPERTS

     154   

WHERE YOU CAN FIND MORE INFORMATION

     154   

INDEX TO FINANCIAL STATEMENTS

     F-1   

GLOSSARY

     G-1   

 

 

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on our behalf or to the information which we have referred you. Neither we, the selling shareholders nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We, the selling shareholders and the underwriters are offering to sell shares of Class A common stock and seeking offers to buy shares of Class A common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of any sale of the Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Through and including                     , 2014 (the 25th day after the date of this prospectus), all dealers effecting transactions in our shares, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable as of their respective dates, neither we, the selling shareholders nor the underwriters have independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

 

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Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

 

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully before making an investment decision, including the information under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical and pro forma consolidated financial statements and the related notes thereto appearing elsewhere in this prospectus. References to our estimated proved reserves as of December 31, 2013 are derived from our proved reserve report (the “NSAI Report”) prepared by Netherland, Sewell & Associates, Inc. (“NSAI”). The information presented in this prospectus assumes (i) an initial public offering price of $             per share of Class A common stock (the midpoint of the price range set forth on the cover of this prospectus) and (ii) unless otherwise indicated, that the underwriters do not exercise their option to purchase additional shares of Class A common stock. In this prospectus, unless the context otherwise requires, the terms “we,” “us” and “our” refer to Parsley Energy, LLC (“Parsley LLC”) and its subsidiaries before the completion of our corporate reorganization in connection with this offering and Parsley Energy, Inc. (“Parsley Inc.”) and its subsidiaries as of the completion of our corporate reorganization and thereafter. Please read “Corporate Reorganization.” We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the “Glossary.”

Our Company

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. The Permian Basin is located in West Texas and Southeastern New Mexico and is comprised of three primary sub-areas: the Midland Basin, the Central Basin Platform and the Delaware Basin. These areas are characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons, extensive production histories, long-lived reserves and historically high drilling success rates. Our properties are primarily 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 intend to supplement our vertical development drilling activity with horizontal wells targeting various stacked pay intervals in the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline) and Atoka shales.

We began operations in August 2008 when we acquired operator rights to wells producing from the Spraberry Trend in the Midland Basin from Joe Parsley, a co-founder of Parker and Parsley Petroleum Company. As of December 31, 2013, we continue to operate 98 gross (2.5 net) of these wells. Excluding those legacy 98 gross wells, as of December 31, 2013 we had an average working interest of 57% in 431 gross producing wells. In total, we have interests in 530 gross (247 net) producing wells, all of which are in the Midland Basin and 99% of which we operate. Since our inception, we have leased or acquired 98,656 net acres in the Permian Basin, approximately 76,356 of which is in the Midland Basin. Since we commenced our drilling program in November 2009, we have operated up to 10 rigs simultaneously and averaged nine operated rigs for the 12 months ended December 31, 2013. Driven by our large-scale drilling program in the core of the Midland Basin, we have grown our net average daily production to 11,139 Boe/d for the month ended March 31, 2014, substantially all of which is organic growth from wells we have drilled. We are currently operating nine vertical drilling rigs and one horizontal drilling rig and expect to operate seven to eight vertical rigs and increase to five horizontal rigs by the first quarter of 2015.

We intend to grow our reserves and production through the development, exploitation and drilling of our multi-year inventory of identified potential drilling locations. As of December 31, 2013, we have identified 1,362 80- and 40-acre potential vertical drilling locations, 1,694 20-acre potential vertical drilling locations and 1,315 potential horizontal drilling locations on our existing acreage, excluding our Gaines County (Midland Basin) and

 

 

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Southern Delaware Basin acreage. As we expand our drilling program to our undeveloped Midland Basin acreage in Gaines County (Midland Basin) and our Southern Delaware Basin acreage, we expect to identify additional vertical and horizontal drilling locations. 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. Additionally, we commenced our vertical appraisal drilling program in the Delaware Basin during the first quarter of 2014 and expect to drill three vertical appraisal wells in 2014. We believe our acreage in the Delaware Basin may also benefit from the application of horizontal drilling and completion techniques. We expect to supplement organic growth from our drilling program by proactively leasing additional acreage and selectively pursuing acquisitions that meet our strategic and financial objectives, with an emphasis on oil-weighted reserves in the Midland Basin.

Our 2014 capital budget for drilling and completion is approximately $430.0 million for an estimated 151 gross (129 net) vertical wells and 30 gross (23 net) horizontal wells. Our capital budget excludes acquisitions. We anticipate that substantially all of our 2014 capital budget will be directed toward the Midland Basin. During the twelve months ended December 31, 2013, our aggregate drilling and completion capital expenditures were $268.4 million, excluding acquisitions. We expect the average working interest in wells we drill during 2014 will be approximately 75% to 85%.

The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these 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.

We measure the expected return of our wells based on estimated ultimate recovery (“EUR”) and the related costs of acquisition, development and production. Based on estimates prepared by NSAI, type curves for vertical locations in our Midland Basin-Core and Midland Basin-Tier I areas have average EURs of 214.8 MBoe (109.1 MBbls of oil, 300.5 MMcf of natural gas and 55.6 MBbls of NGLs) and 109.3 MBoe (69.0 MBbls of oil, 114.5 MMcf of natural gas and 21.2 MBbls of NGLs), respectively. These estimates assume average 30-day initial production rates of 149.7 Boe/d (76.0 Bbls/d of oil, 209.3 Mcf/d of natural gas and 38.8 Bbls/d of NGLs) and 84.5 Boe/d (53.3 Bbls/d of oil, 88.5 Mcf/d of natural gas and 16.4 Bbls/d of NGLs), respectively, which is consistent with the performance of our existing producing wells in these areas. We have no proved undeveloped locations on our Midland Basin-Other or Southern Delaware Basin properties. To date, the average drilling, completion and facilities cost for the 201 and 125 vertical development wells we have drilled and placed on production in our Midland Basin-Core and Midland Basin-Tier I areas, respectively, is approximately $2.3 million and approximately $2.0 million, respectively. The average 2-stream 30-day initial production rate for all of the wells we drilled during the third and fourth quarters of 2013 was 153 Boe/d (comprised of 90 Bbls/d of oil and 373 Mcf/d of natural gas, which includes NGLs). Please see “—Recent Developments—Recent Well Results.”

 

 

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The following table summarizes our acreage and technically identified drilling locations in the Permian Basin as of December 31, 2013:

 

     Net Acreage      Identified Drilling Locations(1)      Vertical
Drilling
Inventory

(Years(5))
     Horizontal
Drilling
Inventory

(Years(6))
 
        Vertical(2)      Horizontal(4)        

Area(3)

      80-and 40-acre      20-acre           

Midland Basin-Core

     28,555         824         1,142         764         —           —     

Midland Basin-Tier I

     21,794         447         464         551         —           —     

Midland Basin-Other

     26,007         91         88         –           —           —     

Southern Delaware Basin

     22,300         —           –           –           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Permian Basin

     98,656         1,362         1,694         1,315         20.3 years         28.8 years   
  

 

 

    

 

 

    

 

 

    

 

 

       

 

(1) We have estimated our drilling locations based on well spacing assumptions for the areas in which we operate and other criteria. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our adding additional proved reserves to our existing proved reserves. See ‘‘Risk Factors—Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.” We have not identified any drilling locations at this time on our substantial leasehold positions in the Southern Delaware Basin and in Gaines County in the Midland Basin, due to our limited operating history in these areas.
(2) Our total identified vertical drilling locations include 553 vertical locations on 80- and 40- acre spacing and 11 vertical locations on 20-acre spacing associated with proved undeveloped reserves as of December 31, 2013. Of these 564 vertical locations, 393 are in our Midland Basin-Core area and 171 are in our Midland Basin-Tier I area. The remaining 809 vertical drilling locations on 80- and 40-acre spacing and the 1,683 vertical drilling locations on 20-acre spacing were identified by our engineering and geoscience staff but as of yet have no associated proved reserves.
(3) Our Midland Basin-Core area contains areas of Andrews, Glasscock, Howard, Martin, Midland, Reagan and Upton Counties. Our Midland Basin-Tier 1 area includes areas of Andrews, Borden, Crane, Dawson, Ector, Glasscock, Howard, Irion, Martin, Midland, Reagan and Upton Counties. Our Midland Basin-Other area includes portions of Andrews, Dawson and Gaines Counties. Our Southern Delaware Basin includes portions of Pecos and Reeves Counties. Please see “Business—Our Properties.”
(4) Our target horizontal location count implies 724’ to 870’ between well spacing which is equivalent to five to six wells per 640-acre section per prospective interval. The ultimate spacing may be less than these amounts, which would result in a higher location count, or greater than these amounts, which would result in a lower location count.
(5) Based on spud to release times consistent with our 2013 drilling program and a continuous seven-rig vertical drilling program.
(6) Based on a continuous five-rig program and an estimated spud to release time of 40 days.

We believe the experience gained from our historical vertical drilling program and the information obtained from the results of extensive industry drilling across the Permian Basin have reduced the geological risk and uncertainty associated with drilling vertical wells on our acreage. Our horizontal drilling program is intended to further capture the upside potential that may exist on our properties and increase our well performance and recoveries as compared to drilling vertical wells alone.

As of December 31, 2013, our estimated proved oil and natural gas reserves were 54.8 MMBoe based on a reserve report prepared by NSAI, our independent reserve engineers. Our proved reserves are approximately 54% oil, 23% natural gas liquids, 23% natural gas and 43% proved developed.

 

 

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The following table provides a summary of selected operating information for our properties in each of the basins within which we operate. All information is as of December 31, 2013 except as otherwise noted.

 

    Net Acreage     Estimated Total Proved Reserves(1)     Average
Net Daily
Production
(Boe/d)(3)
    R/P
Ratio
(Years)(4)
    PV-10
(Millions)(5)
 
      Oil
(MMBbls)
    NGLs
(MMBbls)
    Natural
Gas
(MMcf)
    Total
(MMBoe)
    %
Liquids(2)
       

Midland Basin

    76,356        29.507        12.357        77.818        54.834        77        11,139        13.5      $ 731.1   

Delaware Basin

    22,300        —          —          —          —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    98,656        29.507        12.357        77.818        54.834        77        11,139        13.5      $ 731.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance.
(2) Includes both oil and NGLs.
(3) For the month ended March 31, 2014. Represents 5,937 Bbls/d of crude oil, 2,737 Bbls/d NGLs and 14,785 Mcf/d of natural gas.
(4) Represents the number of years proved reserves would last assuming production continued at the average rate for the month ended December 31, 2013. Because production rates naturally decline over time, the R/P Ratio may not be a useful estimate of how long properties should economically produce.
(5) PV-10 was prepared using SEC pricing discounted at 10% per annum, without giving effect to taxes or hedges. PV-10 is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves or for proved, probable or possible reserves calculated using prices other than SEC prices. PV-10 does not take into account the effect of future taxes. Investors should be cautioned that neither PV-10 nor standardized measure represents an estimate of the fair market value of our proved reserves. For a reconciliation of PV-10 of proved reserves based on SEC pricing to standardized measure, see “—Summary Historical and Pro Forma Consolidated Financial Data—Non-GAAP Financial Measures.”

Our Business Strategy

Our business strategy is to increase shareholder value through the following:

 

   

Grow reserves, production and cash flow by exploiting our liquids rich resource base. We intend to selectively develop our acreage base in an effort to maximize its value and resource potential. We intend to pursue drilling opportunities that offer competitive returns that we consider to be low risk based on production history and industry activity in the area, and repeatable as a result of well-defined geological properties over a large area. Through the conversion of our resource base to developed reserves, we will seek to increase our reserves, production and cash flow while generating favorable returns on invested capital. As of December 31, 2013, we have identified 1,362 80- and 40-acre potential vertical drilling locations, 1,694 20-acre potential vertical drilling locations and 1,315 potential horizontal drilling locations on our existing acreage, excluding our Gaines County (Midland Basin) and Southern Delaware Basin acreage. As we expand our drilling program to our undeveloped Gaines County (Midland Basin) and Southern Delaware Basin acreage, we expect to identify additional vertical and horizontal drilling locations on those properties.

 

 

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Optimize our low risk vertical drilling program and capture potential horizontal development opportunities. Our large scale drilling program has historically focused on optimizing our vertical drilling and completion techniques across our Midland Basin acreage. We intend to continue drilling on 80-acre spacing to hold leases by production and to conduct infill drilling on 40-acre downspacing, which generally increases the recovery factor per section and enhances returns because infrastructure is typically in place. We believe opportunities for increased well density exist across our acreage base for both our horizontal and vertical drilling programs and that horizontal drilling may be economical in areas where vertical drilling is currently not economical or logistically viable. We intend to target multiple benches within the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline) and Atoka shales with horizontal wells and believe our horizontal drilling program may significantly increase our recoveries per section as compared to drilling vertical wells alone.

 

   

Improve operational and cost efficiency by maintaining control of our production. We currently operate approximately 99% of the wells in which we have an interest and intend to maintain operational control of substantially all of our producing properties. We believe that retaining control of our production will enable us to increase recovery rates, lower well costs, improve drilling performance and increase ultimate hydrocarbon recovery through optimization of our drilling and completion techniques. Our management team regularly evaluates our operating results against those of other operators in the area in an effort to improve our performance and implement best practices. We have reduced the average time from spud to rig release for our vertical Spraberry and Wolfberry wells from approximately 18 days during 2011 to approximately 16 days in the fourth quarter of 2013. Our average total depth of wells drilled in 2013 was 11,354 feet. We have also reduced our total drilling, completion and facilities costs from a peak average of $2.4 million per well in the first quarter of 2012 to an average of $2.1 million per well in the fourth quarter of 2013. This decrease was driven primarily by a reduction in hydraulic fracturing costs and efficiencies gained through economies of scale over this time period.

 

   

Pursue additional leasing and strategic acquisitions. We intend to focus primarily on increasing our acreage position through leasing in our Midland Basin-Core area, while selectively pursuing other acquisition opportunities that meet our strategic and financial objectives. Our acreage position extends through what we believe are multiple oil and natural gas producing stratigraphic horizons in the Midland Basin, which we refer to as the stacked pay core, and we believe we can economically and efficiently add and integrate additional acreage into our current operations. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential and believe our management team’s extensive experience operating in the Midland Basin provides us with a competitive advantage in identifying leasing opportunities and acquisition targets and evaluating resource potential.

 

   

Maintain financial flexibility. We intend to maintain a conservative financial position to allow us to develop our drilling, exploitation and exploration activities and maximize the present value of our oil-weighted resource potential. We intend to fund our growth with cash flow from operations, liquidity under our revolving credit facility and access to capital markets over time. After giving effect to this offering and the use of the proceeds therefrom, we will have $         million of liquidity, with $         million of cash and cash equivalents and $         million of available borrowing capacity under our revolving credit facility. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to hedge approximately 40% to 60% of our expected oil production on a rolling 24 to 36 month basis, reducing our exposure to downside commodity price fluctuations and enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities. In addition, as a result of the recent increase in natural gas prices, we have hedged 2,000,000 MMBtus and 3,600,000 MMBtus of our expected 2014 and 2015 natural gas production, respectively.

 

 

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Our Strengths

We believe that the following strengths will help us achieve our business goals:

 

   

Liquids rich, multi-year vertical drilling inventory in the core of one of North America’s leading oil resource plays. All of our leasehold acreage is located in one of the most prolific resource plays in North America, the Permian Basin in West Texas. The majority of our current properties in the Midland Basin are positioned in what we believe to be the stacked pay fairway of the Spraberry, Wolfberry and Wolftoka Trends. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. We view our identified vertical drilling inventory in the Midland Basin as substantially “de-risked” based on our extensive drilling and production history in the area and well-established industry activity surrounding our acreage. As of December 31, 2013, our estimated net proved reserves consisted of approximately 54% oil, 23% natural gas liquids and 23% natural gas.

 

   

Extensive horizontal development potential. We believe there are a significant number of horizontal locations on our acreage that will allow us to target the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline) and Atoka shales. In addition, based on our analysis of data acquired through our vertical drilling program and the activities of offset operators, we believe that multiple benches contained within our acreage may have significant resource potential, which could substantially increase the ultimate hydrocarbon recovery of each surface acre we have under leasehold. Excluding our Gaines County (Midland Basin) and Southern Delaware Basin acreage, we had 1,315 identified potential horizontal drilling locations as of December 31, 2013. During 2013, we spud our first horizontal well in the Wolfcamp B interval across North Upton and Southern Midland Counties and plan to ramp up to five horizontal rigs by the first quarter of 2015. We currently expect to drill 30 additional gross (23 net) horizontal wells during 2014. As we continue to expand our vertical drilling program to our undeveloped acreage in Gaines County (Midland Basin) and the Southern Delaware Basin, we expect to identify additional horizontal drilling locations.

 

   

Incentivized management team with substantial technical and operational expertise. Our management team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Spraberry, Wolfberry and Wolftoka Trends of the Permian Basin. Our chief executive officer, Bryan Sheffield, is a third generation oil and gas executive, and our management team has previous experience at Parker and Parsley Petroleum Company (“Parker and Parsley”), Concho Resources (“Concho”) and Pioneer Natural Resources (“Pioneer”). We have also assembled a technical team that includes six petroleum engineers and two geologists, which we believe will be of strategic importance as we continue to expand our future exploration and development plans. After giving effect to this offering, our management team will hold approximately     % of our ownership interest and will be our largest shareholder group. We believe our management team’s significant ownership interest provides meaningful incentive to increase the value of our business for the benefit of all shareholders.

 

   

Operating control over approximately 99% of our production. As of December 31, 2013, we operated approximately 99% of the wells in which we have an interest. We believe that maintaining control of our production enables us to dictate the pace of development and better manage the cost, type and timing of exploration, exploitation and development activities. Our leasehold position is comprised primarily of properties that we operate and, excluding our Gaines County (Midland Basin) and Southern Delaware Basin acreage, includes an estimated 1,362 80- and 40-acre potential vertical drilling locations, 1,694 20-acre potential vertical drilling locations and 1,315 potential horizontal drilling locations.

 

   

Conservative balance sheet. We expect to maintain financial flexibility that will allow us to develop our drilling activities and selectively pursue acquisitions. After consummation of the transactions contemplated by this prospectus, we expect to have $         million in debt outstanding under our revolving credit facility and $         million of available borrowing capacity. We believe this borrowing capacity, along with our cash flow from operations, will provide us with sufficient liquidity to execute on our current capital program.

 

 

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Recent Developments

Recent Well Results

The following table provides a summary of all wells completed during the third and fourth quarters of 2013 that have sufficient production data:

 

Area

  

Well Count

     30-Day Average
IP Rate (Boe/d)
     90-Day Average Cumulative
Production (Boe)
     Average Total
Depth (feet)
 

Midland Basin – Core

     34         167(1)         11,099         11,733   

Midland Basin – Tier I

     10         104(2)         7,413         11,072   

 

(1) Consisting of 94 Bbls/d of oil and 440 Mcf/d of natural gas. NGLs production and sales are included in our natural gas production and sales.
(2) Consisting of 79 Bbls/d of oil and 147 Mcf/d of natural gas. NGLs production and sales are included in our natural gas production and sales.

Recent Horizontal Operating Results

In November 2013, we commenced our horizontal drilling program in the Midland Basin with one rig targeting various intervals in the Wolfcamp shale. As of March 31, 2014, we had two wells on production (Dusek 45-1HB and Shackelford 7-1HB), one well undergoing a fracture stimulation treatment (Dusek 44-1HB) and one well being drilled (Shackelford 7-2HB).

The Dusek 45-1HB had a 24-hour peak rate of 2,044 Boe/d (1,487 Bbls/d of oil, 387 Bbls/d of NGLs and 1,017 Mcf/d of natural gas) and a peak 30-day rate of 1,591 Boe/d (1,156 Bbls/d of oil, 303 Bbls/d of NGLs and 796 Mcf/d of natural gas) and is currently producing while on gas lift. We do not currently have sufficient production data for the Shackelford 7-1HB well.

The Dusek 45-1HB targeted the Wolfcamp B and was completed utilizing 39 frac stages over a 9,061’ stimulated interval. The Shackelford 7-1HB also targeted the Wolfcamp B and was completed utilizing 21 frac stages over a 4,571’ stimulated interval and is currently producing. The Dusek 44-1HB is targeting the Wolfcamp B and is undergoing fracture stimulation. The Shackelford 7-2HB is targeting the Wolfcamp B and is currently drilling.

Recent Acquisition Activity

On April 10, 2014, we entered into an agreement pursuant to which we acquired an option to purchase 5,040 gross (4,867 net) acres primarily in our Midland Basin-Core area (the “Optioned Acreage”) for total consideration of $132.8 million (net of a $1.0 million option fee). There is de minimis production associated with this acreage. The option is exercisable at any time within the ten day period following the consummation of this offering, and expires on July 31, 2014. Closing of the acquisition is subject to satisfaction of customary closing conditions, including completion of title and other diligence. We can provide no assurance that we will exercise the option or complete the acquisition on the terms described or at all. In the event that we exercise the option and consummate the acquisition, we expect to use a portion of the net proceeds from this offering to fund the purchase price of these assets. See “Use of Proceeds.”

On March 27, 2014, we entered into a purchase and sale agreement pursuant to which we agreed to acquire 2,240 gross (2,005 net) acres in our Midland Basin-Core area and seven gross (6.3 net) wells producing approximately 1,117 gross (1,000 net) Boe/d, for total consideration of $169 million (the “Acreage Acquisition”). The purchase and sale agreement has an anticipated closing date of May 1, 2014 subject to customary closing conditions. We can provide no assurance that we will be able to consummate the Acreage Acquisition.

 

 

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Senior Unsecured Notes

On February 5, 2014, Parsley LLC and Parsley Finance Corp. issued $400 million of 7.5% senior unsecured notes due February 15, 2022. 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 Parsley Finance Corp. The issuance of these notes resulted in net proceeds, after discounts and offering expenses, of approximately $391 million, $198.5 million of which was used to repay all outstanding borrowings, accrued interest and a prepayment penalty under our 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 our revolving credit facility.

Corporate Reorganization

Parsley Inc. was incorporated by Parsley LLC as a Delaware corporation in December 2013. Following this offering and the transactions related thereto, Parsley Inc. will be a holding company whose sole material asset will consist of a membership interest in Parsley LLC. Parsley LLC owns all of the outstanding equity interests in Parsley Energy, L.P. (“Parsley LP”), Parsley Energy Management, LLC (“PEM”) and Parsley Energy Operations, LLC (“PEO”), the operating subsidiaries through which we operate our assets. After the consummation of the transactions contemplated by this prospectus, Parsley Inc. will be the sole managing member of Parsley LLC and will be responsible for all operational, management and administrative decisions relating to Parsley LLC’s business and will consolidate the financial results of Parsley LLC and its subsidiaries. The Limited Liability Company Agreement of Parsley LLC will be amended and restated as the First Amended and Restated Limited Liability Company Agreement of Parsley LLC (the “Parsley Energy LLC Agreement”) to, among other things, admit Parsley Inc. as the sole managing member of Parsley LLC.

In connection with this offering, (a) all of the membership interests (including outstanding incentive units) in Parsley LLC held by its existing owners, including Natural Gas Partners, through NGP X US Holdings, L.P. (collectively “NGP”), and all of our executive officers (the “Existing Owners”), will be converted into a single class of units in Parsley LLC, which we refer to in this prospectus as “PE Units,” using an implied equity valuation for Parsley LLC prior to the offering based on the initial public offering price to the public for our Class A common stock set forth on the cover page of this prospectus and the current relative levels of ownership in Parsley LLC, (b) certain of the Existing Owners, including NGP, will contribute all of their PE Units to Parsley Inc. in exchange for an equal number of shares of Class A common stock, (c) certain of the Existing Owners, including our executive officers, will contribute only a portion of their PE Units to Parsley Inc. in exchange for an equal number of shares of Class A common stock and will continue to own a portion of the PE Units following this offering, (d) Parsley Energy Employee Holdings, LLC, an entity owned by certain of our officers and employees formed to hold a portion of the incentive units in Parsley LLC, will merge with and into Parsley Inc., with Parsley Inc. surviving the merger, and the members of Parsley Energy Employee Holdings, LLC will receive shares of Class A common stock in the merger, (e) Parsley Inc. will issue and contribute                  shares of its Class B common stock and $         million in cash to Parsley LLC in exchange for                  PE Units and (f) Parsley LLC will distribute to each of the Existing Owners that will continue to own PE Units following this offering (collectively, the “PE Unit Holders”), one share of Class B common stock for each PE Unit such PE Unit Holder holds. After giving effect to these transactions and the offering contemplated by this prospectus, Parsley Inc. will own an approximate     % interest in Parsley LLC (or     % if the underwriters’ option to purchase additional shares is exercised in full) and the PE Unit Holders will own an approximate     % interest in Parsley LLC (or     % if the underwriters’ option to purchase additional shares is exercised in full). Please see “Principal and Selling Shareholders.”

Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A common stock and Class B common stock will vote

 

 

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together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. We do not intend to list Class B common stock on any stock exchange.

The PE Unit Holders will have the right to exchange (the “Exchange Right”) all or a portion of their PE Units (together with a corresponding number of shares of Class B common stock) for Class A common stock (or cash at our election (the “Cash Option”)) at an exchange ratio of one share of Class A common stock for each PE Unit (and corresponding share of Class B common stock) exchanged as described under “Certain Relationships and Related Party Transactions—Parsley Energy LLC Agreement.” In addition, the PE Unit Holders and NGP will have the right, under certain circumstances, to cause us to register the offer and resale of their shares of Class A common stock as described under “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

We will enter into a Tax Receivable Agreement with Parsley LLC and the PE Unit Holders. This agreement generally provides for the payment by Parsley Inc. to an exchanging PE Unit Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that Parsley Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after this offering as a result of (i) the tax basis increases resulting from the exchange 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 us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. Parsley Inc. will retain the benefit of the remaining 15% of these cash savings. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

 

 

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The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

 

LOGO

 

 

(1) Includes all of our executive officers and NGP. See “Corporate Reorganization—Existing Owners Ownership” on page 127.
(2) Spraberry Production Services, LLC is not consolidated in our financial statements.

 

 

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Our Principal Shareholders

Upon completion of this offering, the Existing Owners will initially own                 shares of Class A common stock,                  PE Units and                  shares of Class B common stock, representing approximately     % of the voting power of Parsley Inc. For more information on our reorganization and the ownership of our common stock by our principal and selling shareholders, see “Corporate Reorganization” and “Principal and Selling Shareholders.”

In June 2013, Natural Gas Partners, through NGP X US Holdings, L.P., and other investors, including all of our executive officers (the “PSP Members”), provided $73.5 million in exchange for equity interests in Parsley LLC that will be exchanged for shares of our Class A common stock in connection with this offering and that are entitled to a 9.5% return on their invested capital (the “Preferred Return”). We intend to use a portion of the proceeds of this offering to make a cash payment in settlement of the Preferred Return. As of March 31, 2014, the cash payment accrued with respect to the Preferred Return was approximately $5.6 million, of which 88.4% relates to NGP’s investment and the remainder to the PSP Members’ investment.

Founded in 1988, NGP is a family of energy-focused private equity funds with over $10 billion in aggregate committed capital under management since inception. After giving effect to this offering, NGP will hold approximately     % of our Class A common stock.

Risk Factors

Investing in our Class A common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 22 for an explanation of these risks before investing in our Class A common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our Class A common stock and a loss of all or part of your investment:

 

   

Oil and natural gas prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

 

   

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

 

   

Our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

 

   

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

   

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area.

 

   

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

 

   

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

 

 

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We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

 

   

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

 

   

We are subject to complex federal, state, local and other laws and regulations related to environmental, health, and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

 

   

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

For a discussion of other considerations that could negatively affect us, see “Risk Factors” beginning on page 22 and “Cautionary Note Regarding Forward-Looking Statements” on page 47 of this prospectus.

Emerging Growth Company Status

We are an “emerging growth company” within the meaning of the federal securities laws. For as long as we are an emerging growth company, we will not be required to comply with certain requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and the exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, or the “Securities Act,” for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies.

We intend to take advantage of these exemptions until we are no longer an emerging growth company. We will cease to be an “emerging growth company” upon the earliest of: (i) the last day of the fiscal year in which we have $1.0 billion or more in annual revenues; (ii) the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or (iv) the last day of the fiscal year following the fifth anniversary of our initial public offering.

For a description of the qualifications and other requirements applicable to emerging growth companies and certain elections that we have made due to our status as an emerging growth company, see “Risk Factors—Risks Related to the Offering and our Class A Common Stock—For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies” on page 46 of this prospectus.

Our Offices

Our principal executive offices are located at 500 West Texas Ave., Tower I, Suite 200, Midland, Texas, 79701 and our telephone number at that address is (432) 818-2100. Effective August 1, 2014, our principal executive offices will be located at 303 Colorado Street, Austin, Texas 78701. Our website address is www.parsleyenergy.com. Information contained on our website does not constitute part of this prospectus.

 

 

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THE OFFERING

 

Class A common stock offered by us

                 shares (                 shares if the underwriters’ option to purchase additional shares is exercised in full).

 

Class A common stock offered by the selling shareholders

                 shares.

 

Total Class A common stock offered

                 shares.

 

Class A common stock to be outstanding immediately after completion of this offering

                 shares (                 shares if the underwriters’ option to purchase additional shares is exercised in full).

 

Class A common stock owned by the selling shareholders after this offering

                 shares.

 

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to an aggregate of                  additional shares of our Class A common stock.

 

Class B common stock to be outstanding immediately after completion of this offering

                 shares, or one share for each PE Unit held by the PE Unit Holders immediately following this offering. Class B shares are non-economic. When a PE Unit is exchanged for a share of Class A common stock, a corresponding share of Class B common stock will be cancelled.

 

Voting Power of Class A common stock after giving effect to this offering

    % or (or 100% if all outstanding PE Units held by the PE Unit Holders are exchanged, along with a corresponding number of shares of our Class B common stock, for newly-issued shares of Class A common stock on a one-for-one basis).

 

Voting Power of Class B common stock after giving effect to this offering

    % or (or 0% if all outstanding PE Units held by the PE Unit Holders are exchanged, along with a corresponding number of shares of our Class B common stock, for newly-issued shares of Class A common stock on a one-for-one basis).

 

Voting rights

Each share of our Class A common stock entitles its holder to one vote on all matters to be voted on by shareholders generally. Each share of our Class B common stock entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. See “Description of Capital Stock.”

 

 

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Use of proceeds

We expect to receive approximately $         million of net proceeds from the sale of the Class A common stock offered by us, based upon the assumed initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us (or approximately $         million if the underwriters’ option to purchase additional shares is exercised in full). Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $         million (assuming no exercise of the underwriters’ option to purchase additional shares).

 

  We intend to contribute the $         million of net proceeds to Parsley LLC in exchange for PE Units. Parsley LLC will use (i) approximately $         million to make a cash payment in settlement of the Preferred Return, (ii) $         million to reduce amounts drawn under Parsley LLC’s revolving credit facility, (iii) $         million to fund the consideration for the acquisition of the Optioned Acreage and related fees and expenses and (iv) any remaining net proceeds to fund a portion of our exploration and development program. In the event the acquisition of the Optioned Acreage does not close, we would use the net proceeds for general corporate purposes, including to fund a portion of our exploration and development program. Please see “Use of Proceeds.”

 

  We will not receive any of the proceeds from the sale of shares of our Class A common stock by the selling shareholders.

 

Conflicts of Interest

A portion of the net proceeds from this offering will be used to repay borrowings under our revolving credit facility. Because affiliates of Wells Fargo Securities, LLC and J.P. Morgan Securities LLC are lenders under our revolving credit facility and will receive 5% or more of the net proceeds of this offering, Wells Fargo Securities, LLC and J.P. Morgan Securities LLC are deemed to have a “conflict of interest” under Rule 5121 of the Financial Industry Regulatory Authority, Inc. (“FINRA”). As a result, this offering will be conducted in accordance with FINRA Rule 5121. Pursuant to that rule, the appointment of a “qualified independent underwriter” is not required in connection with this offering as the members primarily responsible for managing the public offering do not have a conflict of interest, are not affiliates of any member that has a conflict of interest and meet the requirements of paragraph (f)(12)(E) of FINRA Rule 5121. See “Use of Proceeds” and “Underwriting (Conflicts of Interest)” beginning on pages 49 and 148, respectively for additional information.

 

Exchange rights of PE Unit Holders

Under the Parsley Energy LLC Agreement, PE Unit Holders may exchange their PE Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) or, at our option, the Cash Option.

 

 

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Dividend policy

We do not anticipate paying any cash dividends on our Class A common stock. In addition, our revolving credit facility places restrictions on our ability to pay cash dividends. See “Dividend Policy.”

 

Directed Share Program

The underwriters have reserved for sale at the initial public offering price up to     % of the Class A common stock being offered by this prospectus for sale to our employees, executive officers, directors, business associates and related persons who have expressed an interest in purchasing Class A common stock in the offering. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Please read “Underwriting (Conflicts of Interest)” beginning on page 148.

 

Listing and trading symbol

We have applied to list our Class A common stock on the New York Stock Exchange (“NYSE”) under the symbol “PE.”

 

Risk Factors

You should carefully read and consider the information beginning on page 22 of this prospectus set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our Class A common stock.

The information above does not include shares of Class A common stock reserved for issuance pursuant to our equity incentive plan.

 

 

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SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

Parsley Inc. was formed in December 2013 and does not have historical financial operating results. The following table shows summary historical and pro forma consolidated financial data of our accounting predecessor, Parsley LLC and its predecessors, for the periods and as of the dates presented. Parsley LLC was formed on June 11, 2013. Concurrent with the formation of Parsley LLC, all of the interest holders in Parsley Energy, L.P., Parsley Energy Management, LLC and Parsley Energy Operations, LLC exchanged their interests in each such entity for common units in Parsley LLC (the “Exchange”). The Exchange was treated as a reorganization of entities under common control. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Financial Condition and Results of Operations,” our future results of operations will not be comparable to the historical results of our predecessor.

The summary historical consolidated financial data as of December 31, 2012 and 2013 and for the years ended December 31, 2011, 2012 and 2013 were derived from the audited historical consolidated and combined financial statements of our predecessor included elsewhere in this prospectus.

The summary unaudited pro forma consolidated statement of operations data for the year ended December 31, 2013 has been prepared to give pro forma effect to (i) the reorganization transactions described under “Corporate Reorganization,” (ii) the acquisition in December 2013 of non-operated working interests in a number of wells for aggregate consideration of approximately $79.3 million (the “Merit Acquisition”), (iii) the repayment and termination of our second lien credit facility and the repayment of amounts drawn under our revolving credit facility and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2013. The summary unaudited pro forma consolidated balance sheet as of December 31, 2013 has been prepared to give pro forma effect to these transactions as if they had been completed on December 31, 2013. The summary unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

 

 

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You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Corporate Reorganization,” the historical consolidated financial statements of our predecessor and the pro forma consolidated financial statements of Parsley Inc. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the following information.

 

    Year Ended
December 31,
    Parsley
Energy, Inc.
 
      Pro Forma  
      Year Ended
December 31,

2013
 
    2011     2012     2013    
                      (Unaudited)  
   

(in thousands, except per share data)

 

Consolidated Statements of Operations Data:

       

Revenues:

       

Oil sales

  $ 8,702      $ 30,443      $ 97,839      $                

Natural gas and natural gas liquids sales

    2,132        7,236        23,179     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    10,834        37,679        121,018     
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses:

       

Lease operating expenses

    1,446        4,646        16,572     

Production and ad valorem taxes

    610        2,412        7,081     

Depreciation, depletion and amortization

    1,247        6,406        28,152     

General and administrative expenses

    1,357        3,629        16,481     

Accretion of asset retirement obligations

    32        66        181     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

    4,692        17,159        68,467     

Gain on sales of oil and natural gas properties

    6,638        7,819        36     
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    12,780        28,339        52,587     

Other income (expense):

       

Interest expense, net

    (458)        (6,285)        (13,714)     

Prepayment premium on extinguishment of debt

    —          (6,597)        —       

Income of equity investment

    136        267        184     

Derivative loss

    (255)        (2,190)        (9,800)     

Other income (expense)

    (267)        (81)        159     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense), net

    (844)        (14,886)        (23,171)     
 

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

    11,936        13,453        29,416     

Income tax expense(1)

    (116)        (554)        (1,906)     
 

 

 

   

 

 

   

 

 

   

 

 

 

Consolidated net income

    11,820        12,899        27,510     

Less: net income attributable to noncontrolling interest

    —          —          —       
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to stockholders

  $ 11,820      $ 12,899      $ 27,510      $     
 

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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    Year Ended
December 31,
    Parsley
Energy, Inc.
 
      Pro Forma  
      Year Ended
December 31,
 
    2011     2012     2013     2013  
                      (Unaudited)  
   

(in thousands, except per share data)

 

Net income (loss) per common share:

       

Basic

        $     

Diluted

        $     

Weighted average common shares outstanding:

       

Basic

       

Diluted

       

Consolidated Statements of Cash Flows Data:

       

Cash provided by (used in):

       

Operating activities

  $ 16,031      $ 5,025      $ 53,235     

Investing activities

    (15,654)        (89,539)        (425,611)     

Financing activities

    19,729        74,245        378,096     

Consolidated Balance Sheets Data (at period end):

       

Cash and cash equivalents

  $ 23,942      $ 13,673      $ 19,393      $     

Total assets

    64,478        181,239        742,556     

Total debt

    26,118        119,663        430,197     

Total mezzanine equity

    —          —          77,158     

Total members’ equity

    9,053        6,017        30,874     

Other Financial Data:

       

Adjusted EBITDA(2)

  $ 7,265      $ 26,281      $ 75,595      $     

 

(1) Parsley Inc. is a subchapter C corporation (“C-corp”) under the Internal Revenue Code of 1986, as amended, and is subject to federal and State of Texas income taxes. Our predecessor, Parsley LLC was not subject to U.S. federal income taxes. As a result, the consolidated net income in our historical financial statements does not reflect the tax expense we would have incurred as a C-corp during such periods. However, our pro forma financial data gives effect to income taxes, at an effective tax rate of 36%, on the earnings of our predecessor as if it had been subject to federal and state income taxes as a C-corp for the year ended December 31, 2013.
(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is not a measure of net income as determined by United States generally accepted accounting principles (“GAAP”). Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income before depreciation, depletion and amortization, gain (loss) on sales of oil and natural gas properties, asset retirement obligation accretion expense, interest expense, income tax, prepayment premium on extinguishment of debt, gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments and premiums (paid) received on options that settled during the period.

 

 

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Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income for each of the periods indicated.

 

     Year  Ended
December 31,
     Parsley
Energy, Inc.
 
        Pro Forma  
        Year Ended
December 31,
 
     2011      2012      2013      2013  
                          (Unaudited)  

Adjusted EBITDA reconciliation to net income (in thousands):

           

Net income

   $ 11,820       $ 12,899       $ 27,510       $     

Depreciation, depletion and amortization

     1,247         6,406         28,152      

Gain on sales of oil and natural gas properties

     (6,638)         (7,819)         (36)      

Asset retirement obligation accretion expense

     32         66         181      

Interest expense, net

     458         6,285         13,714      

Income tax

     116         554         1,906      

Prepayment premium on extinguishment of debt

     —           6,597         —        

Derivative loss

     255         2,190         9,800      

Net cash receipts (payments) on settled derivative instruments

     78         179         (198)      

Premiums (paid) received on options that settled during the period

     (103)         (1,076)         (5,434)      
  

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 7,265       $ 26,281       $ 75,595       $                
  

 

 

    

 

 

    

 

 

    

 

 

 

PV-10

The following table provides a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure as of December 31, 2013:

 

     As of
December 31,
 
     2013  
     (in millions)  

PV-10 of proved reserves

   $ 731.1   

Present value of future income tax discounted at 10%

     (10.3)   
  

 

 

 

Standardized Measure(1)

   $ 720.8   
  

 

 

 

 

(1) If Parsley Energy had been subject to entity-level U.S. federal income taxes, the pro forma, undiscounted, income tax expense at December 31, 2013, would have been $562.5 million ($233.4 million on a discounted basis) and the Standardized Measure would have been $497.7 million.

 

 

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Summary Reserve and Operating Data

The following tables present summary data with respect to our estimated net proved oil and natural gas reserves and operating data as of the dates presented.

The reserve estimates attributable to our properties at December 31, 2013 presented in the table below are based on a reserve report prepared by NSAI, our independent reserve engineers. The NSAI Report was prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting. The following tables also contain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties.

In evaluating the material presented below, please read “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business—Oil and Natural Gas Data—Proved Reserves,” “Business—Oil and Natural Gas Production Prices and Production Costs—Production and Price History” and our consolidated financial statements and notes thereto.

 

     December 31, 2013(1)  

Proved Reserves

  

Oil (MBbls)

     29,507   

Natural gas (MMcf)

     77,818   

NGLs (MBbls)

     12,357   

Total proved reserves (MBoe)(2)

     54,834   

PV-10 (Thousands)(3)

   $ 731,071   

Proved Developed Reserves

  

Oil (MBbls)

     13,560   

Natural gas (MMcf)

     31,301   

NGLs (MBbls)

     4,762   

Total proved developed (MBoe)(2)

     23,539   

PV-10 (Thousands)(3)

   $ 514,893   

Proved developed reserves as a percentage of total proved reserves

     43

Proved Undeveloped Reserves

  

Oil (MBbls)

     15,947   

Natural gas (MMcf)

     46,517   

NGLs (MBbls)

     7,595   

Total proved undeveloped reserves (MBoe)(2)

     31,295   

PV-10 (Thousands)(3)

   $ 216,178   

Proved undeveloped reserves as a percentage of total proved reserves

     57

Oil and Natural Gas Prices

  

Oil—NYMEX–WTI per Bbl

   $ 92.53   

Natural gas—NYMEX–Henry Hub per MMBtu

   $ 3.46   

 

(1) Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance.
(2) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(3) For a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure as of December 31, 2013, please read “—Non-GAAP Financial Measures.”

 

 

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     Year Ended
December  31,
 
         2011              2012              2013      
     (Unaudited)  

Production and operating data:

        

Net production volumes:

        

Oil (MBbls)

     94         356         1,049   

Natural gas and natural gas liquids (MMcf)

     304         1,493         4,680   

Total (MBoe)(1)

     145         604         1,829   

Average net production (Boe/d)

     397         1,652         5,011   

Average sales prices(2):

        

Oil sales, without realized derivatives (per Bbl)

   $ 92.43       $ 85.60       $ 93.28   

Oil sales, with realized derivatives (per Bbl)

   $ 92.17       $ 83.08       $ 87.91   

Natural gas and natural gas liquids (per Mcf)

   $ 7.02       $ 4.85       $ 4.95   

Average price per BOE, without realized derivatives

   $ 74.84       $ 62.33       $ 66.17   

Average price per BOE, with realized derivatives

   $ 74.67       $   60.85       $ 63.09   

Average unit costs per Boe:

        

Lease operating expenses

   $ 9.99       $ 7.69       $ 9.06   

Production and ad valorem taxes

   $ 4.21       $ 3.99       $ 3.87   

Depreciation, depletion and amortization

   $ 8.61       $ 10.60       $ 15.39   

General and administrative expenses

   $ 9.37       $ 6.00       $ 9.01   

Accretion of asset retirement obligations

   $ 0.22       $ 0.11       $ 0.10   

 

(1) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2) Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains or losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period.

 

 

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RISK FACTORS

Investing in our Class A common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under “Cautionary Note Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil and natural gas prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Natural gas, NGLs and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

 

   

worldwide and regional economic conditions impacting the global supply and demand for natural gas, NGLs and oil;

 

   

the price and quantity of foreign imports;

 

   

political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

 

   

the level of global exploration and production;

 

   

the level of global inventories;

 

   

prevailing prices on local price indices in the areas in which we operate;

 

   

the proximity, capacity, cost and availability of gathering and transportation facilities;

 

   

localized and global supply and demand fundamentals and transportation availability;

 

   

weather conditions;

 

   

technological advances affecting energy consumption;

 

   

the price and availability of alternative fuels; and

 

   

domestic, local and foreign governmental regulation and taxes.

Furthermore, the worldwide financial and credit crisis in recent years has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide resulting in a slowdown in economic activity and recession in parts of the world. This has reduced worldwide demand for energy and resulted in lower natural gas, NGLs and oil prices.

Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that we can produce economically.

If commodity prices further decrease, a significant portion of our exploitation, development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to

 

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our estimated proved reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development and acquisition of oil and natural gas reserves. We expect to fund 2014 capital expenditures with cash generated by operations, the proceeds of this offering, borrowings under our revolving credit facility and possibly through capital market transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our cash flow from operations and access to capital are subject to a number of variables, including:

 

   

our proved reserves;

 

   

the level of hydrocarbons we are able to produce from existing wells;

 

   

the prices at which our production is sold;

 

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our ability to acquire, locate and produce new reserves; and

 

   

our ability to borrow under our credit facility.

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

 

   

delays imposed by or resulting from compliance with regulatory requirements including limitations resulting from wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;

 

   

pressure or irregularities in geological formations;

 

   

shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

 

   

equipment failures or accidents;

 

   

lack of available gathering facilities or delays in construction of gathering facilities;

 

   

lack of available capacity on interconnecting transmission pipelines;

 

   

adverse weather conditions, such as blizzards, tornados and ice storms;

 

   

issues related to compliance with environmental regulations;

 

   

environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

 

   

declines in oil and natural gas prices;

 

   

limited availability of financing at acceptable terms;

 

   

title problems or legal disputes regarding leasehold rights; and

 

   

limitations in the market for oil and natural gas.

 

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Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our $750 million revolving credit facility and our senior unsecured notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our credit facility and the indenture governing our senior unsecured notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our revolving credit facility and the indenture governing our senior unsecured notes contain a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

 

   

incur additional indebtedness;

 

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sell assets;

 

   

make loans to others;

 

   

make investments;

 

   

enter into mergers;

 

   

make certain payments;

 

   

hedge future production or interest rates;

 

   

incur liens; and

 

   

engage in certain other transactions without the prior consent of the lenders.

In addition, our revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our credit facilities impose on us.

Our revolving credit facility limits the amount we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such lenders. Outstanding borrowings in excess of the borrowing base must be repaid.

A breach of any covenant in our revolving credit facility would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the relevant facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, we enter into commodity derivative contracts for a significant portion of our production, primarily consisting of put spreads and three-way collars. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Properties—Sources of Our Revenues—Realized Prices on the Sale of Oil, Natural Gas and NGLs.” Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

 

   

production is less than the volume covered by the derivative instruments;

 

   

the counterparty to the derivative instrument defaults on its contractual obligations;

 

   

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

 

   

there are issues with regard to legal enforceability of such instruments.

 

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The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have an adverse effect on our financial condition.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Approximately 78% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

Approximately 78% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas

 

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regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area.

All of our producing properties are geographically concentrated in the Permian Basin of West Texas. At December 31, 2013, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

The marketing of oil, NGLs and gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there is insufficient capacity available on these systems, or if these systems are unavailable to us, the price offered for our production could be significantly depressed, or we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while we construct our own facility. We also rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transport and sell our oil, NGLs and gas production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transportation, storage or processing facilities to us, especially in areas of planned expansion where such facilities do not currently exist.

Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.

Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as winter storms, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. For example, recent severe winter weather and the resulting extensive power outages caused our production in November to decline significantly from the prior month. Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.

 

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While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2013, 57% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 31 MMBoe of estimated proved undeveloped reserves will require an estimated $492 million of development capital over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

SEC rules could limit our ability to book additional proved undeveloped reserves (PUDs) in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they related to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A writedown constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

 

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Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “Business—Operations—Marketing and Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas. Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

 

   

injury or loss of life;

 

   

damage to and destruction of property, natural resources and equipment;

 

   

pollution and other environmental damage;

 

   

regulatory investigations and penalties;

 

   

suspension of our operations; and

 

   

repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

   

unexpected drilling conditions;

 

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title problems;

 

   

pressure or lost circulation in formations;

 

   

equipment failure or accidents;

 

   

adverse weather conditions;

 

   

compliance with environmental and other governmental or contractual requirements; and

 

   

increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of producing properties or businesses that complement or expand our current business. The successful acquisition of producing properties requires an assessment of several factors, including:

 

   

recoverable reserves;

 

   

future oil and natural gas prices and their applicable differentials;

 

   

operating costs; and

 

   

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our revolving credit facility and the indenture governing our senior unsecured notes impose certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility and the indenture governing our senior unsecured notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

We are subject to complex U.S. federal, state, local and other laws and regulations related to environmental, health, and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain

 

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and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, and results of operations.

Our operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”), and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected. See “Business—Regulation of the Oil and Natural Gas Industry” for a further description of the laws and regulations that affect us.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

 

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Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005, the Federal Regulatory Commission (“FERC”) has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”) to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1 million per day. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Natural Gas Industry.”

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. As part of these efforts, the EPA issued a final rule (the “Tailoring Rule”), effective January 1, 2011, that established emissions thresholds such that only these large stationary sources are subject to GHG permitting. On July 12, 2012, the EPA issued a final rule that retained the previously established thresholds, but those thresholds could be adjusted downward in the future. Despite numerous legal challenges to the EPA’s authority to regulate GHGs, federal courts have affirmed that the EPA does have the authority to regulate GHG emissions under the Clean Air Act. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.

In addition, in August 2012, the EPA established new source performance standards (“NSPS”) for volatile organic compounds and sulfur dioxide and an air toxic standard for oil and natural gas production, transmission, and storage. The rules include the first federal air standards for natural gas wells that are hydraulically fractured, or refractured, as well as requirements for several other sources, such as storage tanks and other equipment, and limits methane emissions from these sources in an effort to reduce GHG emissions. These requirements could adversely affect our operations by requiring us to make significant expenditures to ensure compliance with the NSPS.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress were to undertake comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. In any event, the Obama administration recently announced its Climate

 

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Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas industry. As part of the Climate Action Plan, the Obama Administration also announced that it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies in the coming years. For example, in September 2013, the EPA re-issued proposed NSPS for GHG emissions from Electric Utility Generating Units. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We routinely apply hydraulic fracturing techniques in our drilling and completion programs. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the Safe Drinking Water Act (“SDWA”) involving the use of diesel fuels and issued revised permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. To date, the EPA has not issued a Notice of Proposed Rulemaking, therefore, it is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements may affect our operations. In addition, Congress has from time to time considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Also, in the near future we may be subject to regulations that restrict our ability to discharge water produced as part of our production operations, and the ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. The EPA is currently developing effluent limitation guidelines that may impose federal pre-treatment standards on all oil and gas operators transporting wastewater associated with hydraulic fracturing activities to publicly owned treatment works for disposal. The EPA plans to propose such standards by 2014. In addition, on May 24, 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Native American lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The revised proposed rule would continue to require public disclosure of chemicals used in hydraulic fracturing on federal and Native American lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface.

Further, on April 17, 2012, the EPA released final rules that subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the NSPS and the National Emission

 

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Standards for Hazardous Air Pollutants (“NESHAPS”) programs. These rules became effective on October 15, 2012. The rules include NSPS standards for completions of hydraulically-fractured gas wells. The standards include the reduced emission completion techniques, or “green completions,” developed in the EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. “Green completions” for hydraulic fracturing will require the operator to recover rather than vent the gas and NGLs that come to the surface during completion of the fracturing process. The standards will be applicable to newly drilled and fractured wells and wells that are refractured on or after January 1, 2015. Further, the rules under NESHAPS include Maximum Achievable Control Technology (“MACT”) standards for glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. In April 2013 EPA issued a proposed revision as a result of legal challenges to the original rule which may impact the scope of these rules. The rule is designed to limit emissions of volatile organic compounds (“VOC”), sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oil and natural gas production facilities, and natural gas transmission compressor stations. This rule could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards or performance limiting methane emissions from oil and gas sources is appropriate and if so, to promulgate performance standards for methane emissions from existing oil and gas sources.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices, which could lead to increased regulation. For example, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has also commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012, and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by late 2014. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Further regulation of hydraulic fracturing at the federal, state, and local level could subject our operations to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. Please read “Business—Regulation of the Oil and Natural Gas Industry” for a further description of the laws and regulations that affect us.

 

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Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market oil or natural gas.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.

We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

Our operations and drilling activity are concentrated in the Permian Basin of West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could result in oil and gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our results of operations, liquidity and financial condition.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the United States financial market have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. With the exception of Bryan Sheffield, our President and Chief Executive Officer, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations. For example, in the event that Mr. Sheffield no longer controls the entity that is the sub-operator of the 98 legacy wells we assumed from Parker and Parsley, the sub-operating agreement governing the terms of our arrangement could terminate and we would no longer be the operator of record on these wells. If the sub-operating agreement were to terminate, we would be unable to dictate the pace of development and manage the cost, type, and timing of the drilling program on these identified drilling locations, which could impact our ability to recognize the proved undeveloped reserves associated with these properties.

 

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We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.

We have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

 

   

increased responsibilities for our executive level personnel;

 

   

increased administrative burden;

 

   

increased capital requirements; and

 

   

increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. While horizontal drilling is a significant part of our growth strategy, we have only spud four horizontal wells to date and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

 

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Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated, and additional state taxes on oil and natural gas extraction may be imposed, as a result of future legislation.

The Fiscal Year 2014 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations from local sources, we may be unable to produce oil and natural gas economically, which could have an adverse effect on our financial condition, results of operations and cash flows.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves.

 

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The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide derivative transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

 

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The corporate opportunity provisions in our certificate of incorporation could enable NGP to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

 

   

permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;

 

   

permits any of our shareholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

   

provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (1) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (2) acted in bad faith or in a manner inconsistent with our best interests.

As a result, NGP or their affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to NGP and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read “Description of Capital Stock.”

If we are unable to comply with the restrictions and covenants in our revolving credit facility, there could be an event of default under the terms of our revolving credit facility, which could results in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our revolving credit facility, there could be an event of default under the terms of this facility. Our ability to comply with these restrictions and covenants, including meeting the financial ratios and tests under our revolving credit facility, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our revolving credit facility, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our revolving credit facility or obtain needed waivers on satisfactory terms.

In April 2014, we determined that as of December 31, 2013, we were not in compliance with the quarterly current ratio requirement under our credit facility, which resulted in an event of default under that agreement. On April 11, 2014, we received a waiver of this event of default and are currently in compliance with the current ratio requirement. We cannot give you any assurance that we will be able to obtain waivers for any future or continuing failures to meet financial covenants or that our lenders will not seek to exercise any remedies or accelerate the repayment of our debt as a result of such failures.

Risks Related to the Offering and our Class A Common Stock

We are a holding company. Our sole material asset after completion of this offering will be our equity interest in Parsley LLC and we are accordingly dependent upon distributions from Parsley LLC to pay taxes, make payments under the Tax Receivable Agreement and cover our corporate and other overhead expenses.

We are a holding company and will have no material assets other than our equity interest in Parsley LLC. Please see “Corporate Reorganization.” We have no independent means of generating revenue. To the extent Parsley LLC has available cash, we intend to cause Parsley LLC to make distributions to its unitholders, including us, in an amount sufficient to cover all applicable taxes at assumed tax rates and payments under the Tax Receivable Agreement we will enter into with Parsley LLC and the PE Unit Holders, and to reimburse us for our corporate and other overhead expenses. We are limited, however, in our ability to cause Parsley LLC and its

 

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subsidiaries to make these and other distributions to us due to the restrictions under our credit facilities. To the extent that we need funds and Parsley LLC or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

The initial public offering price of our Class A common stock may not be indicative of the market price of our Class A common stock after this offering. In addition, an active, liquid and orderly trading market for our Class A common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our Class A common stock was not traded on any market. An active, liquid and orderly trading market for our Class A common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock. The initial public offering price will be negotiated between us, the selling shareholders and representatives of the underwriters, based on numerous factors which we discuss in “Underwriting (Conflicts of Interest),” and may not be indicative of the market price of our Class A common stock after this offering. Consequently, you may not be able to sell shares of our Class A common stock at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our stock price:

 

   

our operating and financial performance and drilling locations, including reserve estimates;

 

   

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

 

   

the public reaction to our press releases, our other public announcements and our filings with the SEC;

 

   

strategic actions by our competitors;

 

   

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

   

speculation in the press or investment community;

 

   

the failure of research analysts to cover our Class A common stock;

 

   

sales of our Class A common stock by us, the selling shareholders or other shareholders, or the perception that such sales may occur;

 

   

changes in accounting principles, policies, guidance, interpretations or standards;

 

   

additions or departures of key management personnel;

 

   

actions by our shareholders;

 

   

general market conditions, including fluctuations in commodity prices;

 

   

domestic and international economic, legal and regulatory factors unrelated to our performance; and

 

   

the realization of any risks describes under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

 

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Our principal shareholders will collectively hold a substantial majority of the voting power of our common stock.

Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or our certificate of incorporation. Upon completion of this offering (assuming no exercise of the underwriters’ option to purchase additional shares), the Existing Owners will own approximately     % of our Class A common stock and     % of our Class B common stock (representing     % of our combined economic interest and voting power).

Although the Existing Owners are entitled to act separately in their own respective interests with respect to their stock in us, the Existing Owners will together have the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, they will be able to determine the outcome of all matters requiring shareholder approval, including mergers and other material transactions, and will be able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. The existence of significant shareholders may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in the best interests of our company.

So long as the Existing Owners continue to control a significant amount of our common stock, each will continue to be able to strongly influence all matters requiring shareholder approval, regardless of whether or not other shareholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of the Existing Owners may differ or conflict with the interests of our other shareholders. In addition, NGP and its affiliates may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. NGP and its affiliates may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.

We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our shareholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies, as described under the caption “Certain Relationships and Related Party Transactions.”

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders, including:

 

   

limitations on the removal of directors;

 

   

limitations on the ability of our shareholders to call special meetings;

 

   

establishing advance notice provisions for shareholder proposals and nominations for elections to the board of directors to be acted upon at meetings of shareholders;

 

 

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providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and

 

   

establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by shareholders at shareholder meetings.

In addition, certain change of control events have the effect of accelerating the payment due under our Tax Receivable Agreement, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company. Please see “—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.”

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation will provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Investors in this offering will experience immediate and substantial dilution of $         per share.

Based on an assumed initial public offering price of $         per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our Class A common stock in this offering will experience an immediate and substantial dilution of $         per share in the as adjusted net tangible book value per share of Class A common stock from the initial public offering price, and our as adjusted net tangible book value as of December 31, 2013 after giving effect to this offering would be $         per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

We may invest or spend the proceeds of this offering in ways with which you may not agree or in ways which may not yield a return.

A portion of the net proceeds from this offering are expected to be used for general corporate purposes, including working capital. Our management will have considerable discretion in the application of the net proceeds, and you will not have the opportunity, as part of your investment decision, to assess whether the proceeds are being used appropriately. The net proceeds may be used for corporate purposes that do not increase our operating results or market value. Until the net proceeds are used, they may be placed in investments that do not produce significant income or that may lose value.

 

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We do not intend to pay dividends on our Class A common stock, and our credit facilities place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our Class A common stock appreciates.

We do not plan to declare dividends on shares of our Class A common stock in the foreseeable future. Additionally, our credit facilities place certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your Class A common stock at a price greater than you paid for it. There is no guarantee that the price of our Class A common stock that will prevail in the market will ever exceed the price that you pay in this offering.

Future sales of our Class A common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

Subject to certain limitations and exceptions, the PE Unit Holders may exchange their PE Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of Class A common stock. Additionally, we may issue additional shares of Class A common stock or convertible securities in subsequent public offerings. After the completion of this offering, we will have                  outstanding shares of Class A common stock and                  outstanding shares of Class B common stock. This number includes                      shares that we and the selling shareholders are selling in this offering and shares that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, the Existing Owners will own                  shares of Class A common stock and                  shares of Class B common stock, representing approximately     % (or %              if the underwriters’ option to purchase additional shares is exercised in full) of our total outstanding common stock. All such shares are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting (Conflicts of Interest),” but may be sold into the market in the future. We expect that certain of the Existing Owners will be party to a registration rights agreement with us that will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Employees will be subject to certain restrictions on the sale of their shares for 180 days after the date of this prospectus; however, after such period, and subject to compliance with the Securities Act or exemptions therefrom, these employees may sell such shares into the public market. See “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of                  shares of our Class A common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

 

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The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our Class A common stock.

Our directors and executive officers have entered into lock-up agreements with respect to their Class A common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. Credit Suisse, at any time and without notice, may release all or any portion of the Class A common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then Class A common stock will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital.

We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.

We will enter into a Tax Receivable Agreement with Parsley LLC and the PE Unit Holders. This agreement generally provides for the payment by us to an exchanging PE Unit Holder of 85% of the amount of 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) the tax basis increases resulting from the exchange 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 us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return.

The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Parsley LLC. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The term of the Tax Receivable Agreement will commence upon the completion of this offering and will continue until all such tax benefits have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement by making the termination payment specified in the agreement.

The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including the timing of the exchanges of PE Units, the price of Class A common stock at the time of each exchange, the extent to which such exchanges are taxable, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the Tax Receivable Agreement constituting imputed interest or depletable, depreciable or amortizable basis. We expect that the payments that we will be required to make under the Tax Receivable Agreement could be substantial.

The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in either Parsley Holdings or us. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to certain mergers or other changes of control we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the Tax Receivable Agreement, which calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including the assumption that we have sufficient taxable income to fully utilize such benefits and that any PE Units that the PE Unit Holders or their permitted transferees own on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of such future benefits.

 

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In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control due to the additional transaction cost a potential acquirer may attribute to satisfying such obligations. For example, if the Tax Receivable Agreement were terminated immediately after this offering, the estimated termination payment would be approximately $         million (calculated using a discount rate equal to the LIBOR, plus 100 basis points, applied against an undiscounted liability of $         million). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to the PE Unit Holders will be netted against payments otherwise to be made, if any, to the PE Unit Holders after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the JOBS Act. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (iii) provide certain disclosure regarding executive compensation required of larger public companies or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our Class A common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, 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 prospectus, 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 this 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:

 

   

business strategy;

 

   

reserves;

 

   

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

 

   

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

 

   

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

 

   

realized oil and natural gas prices;

 

   

timing and amount of future production of oil and natural gas;

 

   

hedging strategy and results;

 

   

future drilling plans;

 

   

competition and government regulations;

 

   

ability to obtain permits and governmental approvals;

 

   

pending legal or environmental matters;

 

   

marketing of oil and natural gas;

 

   

leasehold or business acquisitions;

 

   

costs of developing our properties;

 

   

general economic conditions;

 

   

credit markets;

 

   

uncertainty regarding our future operating results; and

 

   

plans, objectives, expectations and intentions contained in this prospectus that are not historical.

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 and natural gas. 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 this prospectus.

 

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Reserve engineering is a process of estimating underground accumulations of oil and natural gas 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 and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this prospectus 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 prospectus 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 prospectus.

 

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USE OF PROCEEDS

We expect the net proceeds from this offering to be approximately $         million, assuming an initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated underwriting discounts and commissions and estimated offering expenses of approximately $         million, in the aggregate.

We intend to contribute the $         million of net proceeds to Parsley LLC in exchange for PE Units. Parsley LLC will use (i) approximately $         million to make a cash payment in settlement of the Preferred Return, (ii) $         million to reduce amounts drawn under Parsley LLC’s revolving credit facility, (iii) $         million to fund the consideration for the acquisition of the Optioned Acreage and related fees and expenses and (iv) any remaining net proceeds to fund a portion of our exploration and development program. In the event the acquisition of the Optioned Acreage does not close, we would use the net proceeds for general corporate purposes, including to fund a portion of our exploration and development program.

Our revolving credit facility matures on September 10, 2018. As of December 31, 2013, the revolving credit facility had a balance of approximately $234.75 million and bore interest at a weighted average interest rate of 3.31%. The borrowings to be repaid were incurred primarily to fund capital expenditures and the growth of our business. While we currently do not have plans to immediately borrow additional amounts under our revolving credit facility, we may at any time reborrow amounts repaid under our revolving credit facility and we expect to do so to fund our capital program and for other general corporate purposes.

We have granted the underwriters a 30-day option to purchase up to an aggregate of                     additional shares of our Class A common stock to cover over-allotments of shares. We will use the proceeds from the sale of these additional shares for to fund our exploration and development program.

A $1.00 increase or decrease in the assumed initial public offering price of $         per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $         million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus remains the same. If the proceeds increase due to a higher initial public offering price or due to the issuance of additional shares, we would use the additional net proceeds to fund our exploration and development program. If the proceeds decrease due to a lower initial public offering price or a decrease in the number of shares issued, then we would reduce by a corresponding amount the net proceeds directed to reduce amounts drawn under Parsley LLC’s revolving credit facility. Any reduction in net proceeds may cause us to need to borrow additional funds under our credit facilities to fund our operations, which would increase our interest expense and decrease our net income.

We will not receive any of the proceeds from the sale of shares of our Class A common stock by the selling shareholders. We will pay all expenses related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling shareholders.

 

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DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our Class A common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our debt agreements restrict our ability to pay cash dividends to holders of our Class A common stock.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2013:

 

   

on an actual basis;

 

   

on an as adjusted basis to give effect to the issuance and sale of $400 million in senior unsecured notes as described under “Prospectus Summary—Recent Developments—Senior Unsecured Notes”; and

 

   

on an as further adjusted basis after giving effect to (i) the transactions described under “Corporate Reorganization,” (ii) the sale of shares of our Class A common stock in this offering at an assumed initial offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus) and (iii) the application of the net proceeds from this offering as set forth under “Use of Proceeds.”

You should read the following table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes appearing elsewhere in this prospectus.

 

     As of December 31, 2013  
     Actual(1)      As
Adjusted
     As Further
Adjusted(2)
 
     (in thousands)  

Cash and cash equivalents

   $ 19,393       $ 38,012       $                    
  

 

 

    

 

 

    

 

 

 

Debt:

        

Revolving credit facility(3)

   $ 234,750       $ 59,950       $     

7.5% Senior Notes due 2022

     —           400,000      

Second lien credit facility(4)

     192,854         —        

Aircraft term loan

     2,593         2,593      
  

 

 

    

 

 

    

 

 

 

Total debt

   $ 430,197       $ 462,543       $     
  

 

 

    

 

 

    

 

 

 

Mezzanine equity(5)

   $ 77,158         77,158       $     
  

 

 

    

 

 

    

 

 

 

Members’ equity

   $ 30,874       $ 25,350       $     

Shareholders’ equity:

        

Class A common stock, $0.01 par value;                shares authorized (pro forma); shares issued and outstanding (pro forma)

     —           —        

Class B common stock, $0.01 par value,                shares authorized (pro forma); shares issued and outstanding (pro forma)

     —           —        

Preferred stock, $0.01 per share;                shares authorized, no shares issued and outstanding (pro forma)

     —           —        

Additional paid-in capital

     —           —        

Accumulated deficit

     —           —        
  

 

 

    

 

 

    

 

 

 

Total shareholders’ equity

   $ —         $ —         $     
  

 

 

    

 

 

    

 

 

 

Total capitalization

   $ 538,229       $ 565,051       $     
  

 

 

    

 

 

    

 

 

 

 

(1) Parsley Inc. was incorporated in December 2013. The data in this table has been derived from the historical consolidated financial statements included in this prospectus which pertain to the assets, liabilities, revenues and expenses of our accounting predecessor.
(2)

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would decrease (increase) total indebtedness by approximately $         million and increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $         million, $         million and $         million, respectively,

 

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assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at an assumed offering price of $         per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would decrease (increase) cash and cash equivalents by approximately $         million and increase (decrease) total indebtedness, additional paid-in capital, total shareholders’ equity and total capitalization by approximately $         million, $         million, $         million and $         million, respectively, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(3) As of April 1, 2014, the borrowing base was $227.5 million, the outstanding amount totaled $130.3 million including an outstanding letter of credit in the amount of $0.3 million, and we were able to incur approximately $97.2 million of indebtedness under our revolving credit facility. After giving effect to the consummation of the corporate reorganization and the application of the net proceeds of this offering, we expect to have $         million of available borrowing capacity under our revolving credit facility.
(4) On February 5, 2014, all amounts outstanding under the second lien credit facility were repaid and the facility was terminated.
(5) On June 11, 2013, Parsley LLC issued membership interests to NGP and other investors for total consideration of $73.5 million. These interest holders were granted certain rights under Parsley LLC’s limited liability company agreement. Included with these rights were (1) the right to receive a return on their invested capital prior to any distribution to any other unit holders and (2) the right to require Parsley LLC to redeem all, but not less than all, of such 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 ceases to be Parsley LLC’s Chief Executive Officer. As the investment by these holders is redeemable at their option, Parsley LLC has reflected this investment outside of permanent equity, under the heading “Mezzanine Equity—Redeemable LLC Units” in Parsley LLC’s Condensed Consolidated Balance Sheet at December 31, 2013, in accordance with Accounting Standards Codification Topic 480, “Distinguishing Liabilities from Equity.”

The information presented above assumes no exercise of the option to purchase additional shares by the underwriters, and is based on the number of shares of our Class A common stock outstanding as of                 , 2014. The table does not reflect shares of Class A common stock reserved for issuance under our long-term incentive plan, which we plan to adopt in connection with this offering.

 

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DILUTION

Purchasers of the Class A common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the Class A common stock for accounting purposes. Our net tangible book value as of December 31, 2013, after giving pro forma effect to the transactions described under “Corporate Reorganization,” was approximately $         million, or $         per share of Class A common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of Class A common stock that will be outstanding immediately prior to the closing of this offering including giving effect to our corporate reorganization. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (assuming the midpoint of the range on the cover of this prospectus and after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of December 31, 2013 would have been approximately $         million, or $         per share. This represents an immediate increase in the net tangible book value of $         per share to our existing shareholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $         per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering (assuming that 100% of our Class B common stock has been exchanged for Class A common stock):

 

Assumed initial public offering price per share

        $   

Pro forma net tangible book value per share as of December 31, 2013 (after giving effect to our corporate reorganization)

     

Increase per share attributable to new investors in the offering

     
  

 

  

 

 

 

As adjusted pro forma net tangible book value per share (after giving effect to our corporate reorganization and this offering)

     
     

 

 

 

Dilution in pro forma net tangible book value per share to new investors in this offering(1)

      $        
     

 

 

 

 

(1) If the initial public offering price were to increase or decrease by $1.00 per share, then dilution in pro forma net tangible book value per share to new investors in this offering would equal $        or $        , respectively.

The following table summarizes, on an adjusted pro forma basis as of December 31, 2013, the total number of shares of Class A common stock owned by existing shareholders (assuming that 100% of our Class B common stock has been exchanged for Class A common stock) and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing shareholders and to be paid by new investors in this offering at $        , the midpoint of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions.

 

     Shares Purchased     Total Consideration        
     Number    Percent     Amount      Percent     Average Price
Per Share
 
     (in millions)  

Existing shareholders(1)

                   $                                 $                

New investors(2)

                   $                      $     
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

Total

                   $                      $     
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

 

(1) The number of shares disclosed for the existing shareholders includes                  shares being sold by the selling shareholders in this offering.
(2) The number of shares disclosed for the new investors does not include the                  shares being purchased by the new investors from the selling shareholders in this offering.

 

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The data in the table excludes                 shares of Class A common stock initially reserved for issuance under our equity incentive plan, based on an assumed public offering price of $         per share (which is the midpoint of the price range set forth on the cover page of this prospectus):

If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to                 , or approximately     % of the total number of shares of Class A common stock.

 

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SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

Parsley Inc. was formed in December 2013 and does not have historical financial operating results. The following table shows selected historical and pro forma consolidated financial data of our accounting predecessor, Parsley LLC and its predecessors, for the periods and as of the dates presented. Parsley LLC was formed on June 11, 2013. Concurrent with the formation of Parsley LLC, all of the interest holders in Parsley Energy, L.P., Parsley Energy Management, LLC and Parsley Energy Operations, LLC exchanged their interests in each such entity for common units in Parsley LLC (the “Exchange”). The Exchange was treated as a reorganization of entities under common control. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Financial Condition and Results of Operations,” our future results of operations will not be comparable to the historical results of our predecessor.

The selected historical consolidated financial data as of December 31, 2012 and 2013 and for the years ended December 31, 2011, 2012 and 2013 were derived from the audited historical consolidated and combined financial statements of our predecessor included elsewhere in this prospectus.

The selected unaudited pro forma consolidated statement of operations data for the year ended December 31, 2013 has been prepared to give pro forma effect to (i) the reorganization transactions described under “Corporate Reorganization” (ii) the Merit Acquisition, (iii) the repayment and termination of our second lien credit facility and the repayment of amounts drawn under our revolving credit facility and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2013. The selected unaudited pro forma consolidated balance sheet as of December 31, 2013 has been prepared to give pro forma effect to these transactions as if they had been completed on December 31, 2013. The selected unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

 

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You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Corporate Reorganization,” the historical consolidated financial statements of our predecessor and the pro forma consolidated financial statements of Parsley Inc. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the following information.

 

    Predecessor     Parsley
Energy, Inc.
 
      Pro Forma  
      Year Ended
December 31,
 
    2011     2012     2013     2013  
                      (Unaudited)  
    (in thousands, except per share data)  

Consolidated Statements of Operations Data:

       

Revenues:

       

Oil sales

  $ 8,702      $ 30,443      $ 97,839      $                

Natural gas and natural gas liquids sales

    2,132        7,236        23,179     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    10,834        37,679        121,018     
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses:

       

Lease operating expenses

    1,446        4,646        16,572     

Production and ad valorem taxes

    610        2,412        7,081     

Depreciation, depletion and amortization

    1,247        6,406        28,152     

General and administrative expenses

    1,357        3,629        16,481     

Accretion of asset retirement obligations

    32        66        181     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

    4,692        17,159        68,467     

Gain on sales of oil and natural gas properties

    6,638        7,819        36     
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    12,780        28,339        52,587     

Other income (expense):

       

Interest expense, net

    (458)        (6,285)        (13,714)     

Prepayment premium on extinguishment of debt

    —          (6,597)        —       

Income of equity investment

    136        267        184     

Derivative loss

    (255)        (2,190)        (9,800)     

Other income (expense)

    (267)        (81)        159     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense), net

    (844)        (14,886)        (23,171)     
 

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

    11,936        13,453        29,416     

Income tax expense(1)

    (116)        (554)        (1,906)     
 

 

 

   

 

 

   

 

 

   

 

 

 

Consolidated net income

    11,820        12,899        27,510     

Less: net income attributable to noncontrolling interest

    —          —          —       
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to stockholders

  $ 11,820      $ 12,899      $ 27,510      $     
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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                      Parsley
Energy, Inc.
 
    Predecessor     Pro Forma  
    Year Ended
December 31,
    Year Ended
December 31,
2013
 
    2011     2012     2013    
                      (Unaudited)  
    (in thousands, except per share data)  

Net income (loss) per common share:

       

Basic

        $     

Diluted

        $     

Weighted average common shares outstanding:

       

Basic

       

Diluted

       

Consolidated Statements of Cash Flows Data:

       

Cash provided by (used in):

       

Operating activities

  $ 16,031      $ 5,025      $ 53,235      $     

Investing activities

    (15,654)        (89,539)        (425,611)     

Financing activities

    19,729        74,245        378,096     

Consolidated Balance Sheets Data (at period end):

       

Cash and cash equivalents

  $ 23,942      $ 13,673      $ 19,393      $     

Total assets

    64,478        181,239        742,556     

Total debt

    26,118        119,663        430,197     

Total mezzanine equity

    —          —          77,158     

Total members’ equity

    9,053        6,017        30,874     

Other Financial Data:

       

Adjusted EBITDA(2)

  $ 7,265      $ 26,281      $ 75,595      $     

 

(1) Parsley Inc. is a subchapter C-corp under the Internal Revenue Code of 1986, as amended, and is subject to federal and State of Texas income taxes. Our predecessor, Parsley LLC was not subject to U.S. federal income taxes. As a result, the consolidated net income in our historical financial statements does not reflect the tax expense we would have incurred as a C-corp during such periods. However, our pro forma financial data gives effect to income taxes, at an effective tax rate of 36%, on the earnings of our predecessor as if it had been subject to federal and state income taxes as a C-corp for the year ended December 31, 2013.
(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus Summary—Summary Historical and Pro Forma Consolidated Financial Data—Non-GAAP Financial Measures.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical and Pro Forma Consolidated Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. 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 below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” 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 Inc. was formed in December 2013 and does not have historical financial operating results. For purposes of this prospectus, our accounting predecessors are 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 LP, PEM and 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.

Following this offering and the transactions related thereto, Parsley Inc. will be a holding company whose sole material asset will consist of                  PE Units. After the consummation of the transactions contemplated by this prospectus, Parsley Inc. will be the managing member of Parsley LLC and will be responsible for all operational, management and administrative decisions relating to Parsley LLC business and will 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 have begun to 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 December 31, 2013, our acreage position was 98,656 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. From the time we began drilling operations in November 2009 through December 2013, we have drilled and placed on production approximately 336 vertical wells across our acreage in the Midland Basin and at times we have operated up to 10 vertical drilling rigs simultaneously. 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. Additionally we commenced our vertical appraisal drilling program in the Delaware Basin during the first quarter of 2014 and expect to drill three vertical appraisal wells in 2014. This activity has allowed us to identify a multi-year inventory of 3,056 potential vertical drilling locations and

 

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1,315 potential horizontal drilling locations on our existing acreage, excluding our Gaines County (Midland Basin) and Southern Delaware Basin acreage. As we continue to expand our drilling activity to our undeveloped acreage, we expect to identify additional horizontal and vertical locations. We expect to continue to actively lease or acquire minimally producing leasehold with additional drilling upside in order to maintain our track record of growing through the drill bit.

As of December 31, 2013, we had interests in 530 gross (247 net) producing wells across our properties. We currently operate 99% of the wells in which we have an interest, all of which are in the Midland Basin. As of December 31, 2013, our total estimated proved reserves were approximately 54.8 MMBoe, of which approximately 43% were classified as proved developed reserves.

How We Evaluate Our Operations

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

 

   

production volumes;

 

   

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

 

   

lease operating expenses;

 

   

capital expenditures; and

 

   

Adjusted EBITDA.

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 years ended December 31, 2013, 2012 and 2011, our revenues were derived 80.8%, 80.8% and 80.3% from oil sales, respectively, and 19.2%, 19.2% and 19.7% from natural gas and NGLs sales, respectively. 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 predecessor’s properties for the years ended December 31, 2011, 2012 and 2013.

 

     Predecessor  
     For the Year Ended
December 31,
 
         2011              2012              2013      

Oil (MBbls)

     94         356         1,049   

Natural gas and natural gas liquid (MMcf)

     304         1,493         4,680   

Total (MBoe)

     145         604         1,829   

Average net production (Boe/d)

     397         1,652         5,011   

Production volumes directly impact our results of operations. For more information about our predecessor’s production volumes, please read “—Predecessor 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

 

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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. Please read “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business” for a discussion of these and other risks affecting our proved reserves and production.

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. However, several projects have recently been implemented and several more are underway to ease these transportation difficulties which we believe could reduce our differentials to NYMEX WTI in the future.

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 NYMEX Henry Hub price, respectively.

 

     Year Ended
December 31,
 
     2011      2012      2013  

Oil

        

NYMEX WTI High

   $ 113.93       $ 109.77       $ 110.53   

NYMEX WTI Low

   $ 75.67       $ 77.69       $ 86.68   

Differential to Average NYMEX WTI

   $ (2.37)       $ (8.13)       $ (5.32)   

Natural Gas

        

NYMEX Henry Hub High

   $ 4.85       $ 3.90       $ 4.46   

NYMEX Henry Hub Low

   $ 2.99       $ 1.91       $ 3.11   

Differential to Average NYMEX Henry Hub

   $ 3.10       $ 1.94       $ 1.17   

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 year ended December 31, 2013, the NYMEX WTI oil price ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl, while the NYMEX Henry Hub natural gas price ranged from a high of $4.46 per MMBtu to a low of $3.11 per MMBtu. For the five years ended December 31, 2013, the NYMEX-WTI oil price ranged from a high of $145.29 per Bbl to a low of $33.87 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $13.58 per MMBtu to a low of $1.91 per MMBtu.

 

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

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

Our open positions as of December 31, 2013 were as follows:

 

Description and Production Period

   Volume
(Bbls)
     Short Put
Price ($/Bbl)
     Long Put
Price ($/Bbl)
     Short Call
Price ($/Bbl)
     Long Call
Price ($/Bbl)
 

Crude Oil Put Spreads:

              

January 2014—June 2014

     54,000       $ 50.00       $ 90.00       $ —         $ —     

February 2014—August 2014

     400,000         55.00         90.00         —           —     

June 2014—August 2014

     60,000         65.00         90.00         —           —     

August 2014

     9,000         50.00         83.00         —           —     

September 2014

     9,000         60.00         80.00         —           —     

October 2014

     9,000         50.00         90.00         —           —     

September 2014—November 2014

     150,000         65.00         90.00         —           —     

January 2015—February 2016

     1,080,000         60.00         90.00         —           —     

February 2015—June 2015

     500,000         60.00         85.00         —           —     

Crude Oil Three-Ways:

              

January 2014—May 2014

     37,500       $ 56.75       $ 90.00       $ 100.00       $ —     

August 2014—October 2014

     135,000         65.00         95.00         125.00         —     

November 2014—January 2015

     300,000         55.00         87.50         120.00         —     

Long Calls:

              

February 2014—June 2014

     35,000       $ —         $ —         $ —         $ 110.00   

Principal Components of Our Cost Structure

Lease Operating Expenses. Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production or ad valorem taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production.

 

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We monitor our operations to ensure that we are incurring lease operating expenses at an acceptable level. For example, we monitor our lease operating expenses per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to assess our lease operating expenses in comparison to other producers. Although we strive to reduce our lease operating expenses, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties. For example, we may increase field level expenditures to optimize our operations, incurring higher expenses in one quarter relative to another or we may acquire or dispose of properties that have different lease operating expenses per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing lease operating expenses on a period to period basis. In addition, since most of our wells were completed relatively recently, they are currently producing at high rates. As with all wells, however, over time production will decrease, which will result in an increase in our lease operating expenses on a per barrel basis. We also expect an increase in our lease operating expenses as we increase the number of wells drilled and operated.

Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.

Depletion, Depreciation and Amortization. Depreciation, depletion and amortization (‘‘DD&A’’) is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method. Please read “—Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting for Oil and Natural Gas Activities” for further discussion.

Impairment Expense. We review our proved properties and unproved leasehold costs for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred.

General and Administrative Expenses. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations including numerous software applications, audit and other fees for professional services and legal compliance. Also included as compensation expense are amounts required to be recognized attributable to issued and outstanding incentive units. See “ – Factors Affecting the Comparability of Our Financial Condition and Results of Operations.”

Gain (Loss) on Derivative Instruments. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil. None of our derivative contracts are designated as hedges for accounting purposes. Consequently, our derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. The amount of future gain or loss recognized on derivative instruments is dependent upon future oil prices, which will affect the value of the contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

Interest Expense. We finance a portion of our working capital requirements and capital expenditures with borrowings under our revolving credit facility and second lien credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our revolving credit facility and second lien credit facility in interest expense. Interest expense also includes the PIK interest on the second lien credit facility and our prior mezzanine debt facility.

 

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Adjusted EBITDA

We define Adjusted EBITDA as net income before depreciation, depletion and amortization, gain (loss) on sales of oil and natural gas properties, asset retirement obligation accretion expense, interest expense, income tax, prepayment premium on extinguishment of debt, gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments and premiums (paid) received on options that settled during the period.

Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements. For further discussion, please read “Prospectus Summary—Summary Historical and Pro Forma Consolidated Financial Data—Non-GAAP Financial Measures.”

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 year ended December 31, 2013, within our general and administrative expenses, 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 NGP and the PSP Members. At December 31, 2013, 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 such, the fair value of the incentive units was remeasured each reporting period, 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 had been rendered at that date. For the year ended December 31, 2013, such expense totaled $1.2 million.

As part of the transactions described under “Corporate Reorganization”, the Parsley LLC’s limited liability company agreement will be amended to provide that all incentive units are to be settled with PE Units, which PE Units will be exchanged for shares of Class A common stock in connection with the consummation of this offering, instead of in cash at some future liquidation date. As a result, as of the effective date of the amendment to the Parsley LLC’s limited liability company agreement, we will begin accounting for the incentive unit awards as equity-classified awards pursuant to ASC Topic 718. This will result in the recognition of $             million of compensation cost equal to the excess of the modified awards’ fair value (based on the midpoint of the price range set forth on the cover page of this prospectus) over the amount of cumulative compensation cost recognized prior to that date.

 

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Public Company Expenses

Upon completion of this offering, 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 shareholders, tax return preparation, independent auditor 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 consolidated financial statements included in this prospectus are based on the financial statements of our accounting predecessors, Parsley LLC and its predecessors, prior to our reorganization in connection with this offering as described in “Corporate Reorganization.” As a result, the historical financial data may not give you an accurate indication of what our actual results would have been if the transactions described in “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 will enter into a Tax Receivable Agreement with the PE Unit Holders and Parsley LLC. This agreement generally provides for the payment by us to an exchanging PE Unit Holder of 85% of the amount of 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) the tax basis increases resulting from the exchange 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 us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

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 taxes has been provided for in our historical results of operations because taxable income was passed through to Parsley LLC’s members. Although we are a corporation under the Code, subject to U.S. federal income taxes at a statutory rate of 35% of pretax earnings, we do not expect to report any income tax benefit or expense attributable to U.S. federal income taxes until the consummation of this offering. At the closing of this offering, we will be taxed as a corporation under the Code and subject to U.S. federal income taxes at a statutory rate of 35% of pretax earnings.

Parsley LLC’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 income that is apportioned to Texas.

Increased Drilling Activity

We began drilling operations in November 2009 and added operated vertical drilling rigs over time. We currently operate nine vertical drilling rigs and one horizontal drilling rig on our properties. Our 2014 capital budget for drilling and completion is approximately $430.0 million for an estimated 151 gross (129 net) vertical wells and 30 gross (23 net) horizontal wells. Our capital budget excludes acquisitions. This represents a 60.2% increase over our $268.4 million 2013 expenditures for drilling and completion.

The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these 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,

 

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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.

Predecessor Results of Operations

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

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:

 

     Year Ended
December 31,
               
     2012      2013      Change      % Change  
     (Unaudited)                

Revenues (in thousands, except percentages):

           

Revenues:

           

Oil sales

   $ 30,443       $ 97,839       $ 67,396         221%   

Natural gas and natural gas liquid sales

     7,236         23,179         15,943         220%   
  

 

 

    

 

 

    

 

 

    

Total revenues

   $ 37,679       $ 121,018       $ 83,339         221%   
  

 

 

    

 

 

    

 

 

    

Average sales prices(1):

           

Oil sales, without realized derivatives (per Bbls)

   $ 85.60       $ 93.28       $ 7.68         9%   

Oil sales, with realized derivatives (per Bbls)

   $ 83.08       $ 87.91       $ 4.83         6%   

Natural gas and natural gas liquids (per Mcf)

   $ 4.85       $ 4.95       $ 0.10         2%   

Average price per BOE, without realized derivatives

   $ 62.33       $ 66.17       $ 3.84         6%   

Average price per BOE, with realized derivatives

   $ 60.85       $ 63.09       $ 2.24         4%   

Production:

           

Oil (MBbls)

     356         1,049         693         195%   

Natural gas and natural gas liquid (MMcf)

     1,493         4,680         3,187         213%   

Total (MBoe)(2)

     604         1,829         1,225         203%   

Average daily production volume:

           

Oil (Bbls/d)

     972         2,874         1,902         196%   

Natural gas and natural gas liquids (Mcf/d)

     4,079         12,823         8,744         214%   

Total (Boe/d)

     1,652         5,011         3,359         203%   

 

(1) Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains or losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period.
(2) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

 

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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.

 

     Year Ended
December 31,
 
     2012     2013  

Average realized oil price ($/Bbl)

   $ 85.60      $ 93.28   

Average NYMEX ($/Bbl)

   $ 93.73      $ 98.61   

Differential to NYMEX

   $ (8.13   $ (5.33

Average realized oil price to NYMEX percentage

     91     95

Average realized natural gas price ($/Mcf)

   $ 4.85      $ 4.95   

Average NYMEX ($/Mcf)

   $ 2.91      $ 3.79   

Differential to NYMEX

   $ 1.94      $ 1.16   

Average realized natural gas price to NYMEX percentage

     167     131

Oil revenues increased 221% from $30.4 million during the year ended December 31, 2012 to $97.8 million during year ended December 31, 2013. The increase is attributable to higher oil production volumes of 693 MBbls in conjunction with an increase in average oil prices of $7.68 per barrel. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $59.3 million while increases in oil prices accounted for a positive change of $8.1 million.

Natural gas and natural gas liquid revenues increased 220% from $7.2 million during the year ended December 31, 2012 to $23.2 million during the year ended December 31, 2013. The revenue increase is primarily a result of an increase in volumes sold of 3,187 MMcf. Natural gas revenue includes revenue from the sale of NGLs volumes.

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

 

     Year Ended
December 31,
               
     2012      2013      Change      % Change  
     (Unaudited)                

Operating expenses (in thousands, except percentages):

           

Lease operating expenses

   $ 4,646       $ 16,572       $ 11,926         257

Production and ad valorem taxes

     2,412         7,081         4,669         194

Depreciation, depletion and amortization

     6,406         28,152         21,746         339

General and administrative expenses

     3,629         16,481         12,852         354

Accretion of asset retirement obligations

     66         181         115         174
  

 

 

    

 

 

    

 

 

    

Total operating expenses

   $ 17,159       $ 68,467       $ 51,308         299
  

 

 

    

 

 

    

 

 

    

Expense per Boe:

           

Lease operating expenses

   $ 7.69       $ 9.06       $ 1.37         18

Production and ad valorem taxes

     3.99         3.87         (0.12)         (3)

Depreciation, depletion and amortization

     10.60         15.39         4.79         45

General and administrative expenses

     6.00         9.01         3.01         50

Accretion of asset retirement obligations

     0.11         0.10         (0.01)         (9)
  

 

 

    

 

 

    

 

 

    

Total operating expenses per Boe

   $ 28.39         37.43       $ 9.04         32
  

 

 

    

 

 

    

 

 

    

Lease Operating Expenses. Lease operating expenses increased 257% from $4.6 million during the year ended December 31, 2012 to $16.6 million during the year ended December 31, 2013. The increase is primarily due to the higher operated well count in the year ended December 31, 2013 as compared to the prior year period.

 

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On a per Boe basis, lease operating expenses increased from $7.69 per Boe to $9.06 per Boe. This increase was attributable to increases in costs for repair and maintenance for 170 new wells added, additional lease operators and increased water disposal activity.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased $4.7 million from $2.4 million during the year ended December 31, 2012 to $7.1 million during the year ended December 31, 2013 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 year ended December 31, 2013 compared to the year ended December 31, 2012.

Depreciation, Depletion and Amortization. DD&A expense increased by $21.8 million from $6.4 million during the year ended December 31, 2012 to $28.2 million for the year ended December 31, 2013 due to an increase in capitalized costs and production volumes.

General and Administrative Expenses. General and administrative expenses increased $12.9 million from $3.6 million during the year ended December 31, 2012 to $16.5 million during the year ended December 31, 2013 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.

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

 

                                                                           
     Year Ended
December 31,
             
     2012     2013     Change     % Change  
     (Unaudited)              

Other income (expense) (in thousands, except percentages):

        

Interest expense, net

   $ (6,285   $ (13,714   $ (7,429     118

Prepayment premium on extinguishment of debt

     (6,597     —          6,597        (100 )% 

Income from equity investment

     267        184        (83     (31 )% 

Derivative loss

     (2,190     (9,800     (7,610     347

Other income (expense)

     (81     159        240        (296 )% 
  

 

 

   

 

 

   

 

 

   

Total other income (expense), net

   $ (14,886   $ (23,171   $ (8,285     56
  

 

 

   

 

 

   

 

 

   

Interest Expense. Interest expense increased $7.4 million from $6.3 million during the year ended December 31, 2012 to $13.7 million in the year ended December 31, 2013 primarily due to higher weighted-average outstanding borrowings under our credit facilities.

Prepayment Premium on Extinguishment of Debt. In 2012, we incurred a $6.6 million cash charge related to a call premium on our then outstanding debt facility. In 2013, there were no such prepayment charges related to debt extinguishment.

Derivative Loss. Loss on derivative instruments grew $7.6 million from $2.2 million during the year ended December 31, 2012 to $9.8 million during the year ended December 31, 2013 primarily as a result of the impact of changing commodity prices on increased hedging activities.

Gain on Sales of Oil and Natural Gas Properties

In August 2013, we sold our interest in seven non-operated wells and 190 net acres for total proceeds of $0.8 million and realized a $36,000 gain on the sale. In April 2012, we sold 2,652 net unevaluated acres for $8.6 million and realized a $7.5 million gain on the sale.

 

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Income Tax Expense

Although our operations have not been subject to federal income tax, our 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 our Texas sourced operating income. During the year ended December 31, 2013, we recognized $1.9 million of expense associated with our Texas margin tax obligation, an increase of $1.3 million, or 244%, as compared to the $0.6 million we recognized during the year ended December 31, 2012. This increase was attributable to our net increase in operating income, the components of which are discussed above.

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

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:

 

     Year Ended
December 31,
               
     2011      2012      Change      % Change  

Revenues (in thousands, except percentages):

           

Revenues:

           

Oil sales

   $ 8,702       $ 30,443       $ 21,741         250

Natural gas and natural gas liquid sales

     2,132         7,236         5,104         239
  

 

 

    

 

 

    

 

 

    

Total revenues

   $ 10,834       $ 37,679       $ 26,845         248
  

 

 

    

 

 

    

 

 

    

Average sales prices(1):

           

Oil sales, without realized derivatives (per Bbls)

   $ 92.43       $ 85.60       $ (6.83)         (7)

Oil sales, with realized derivatives (per Bbls)

   $ 92.17       $ 83.08       $ (9.09)         (10)

Natural gas and natural gas liquids (per Mcf)

   $ 7.02       $ 4.85       $ (2.17)         (31)

Average price per BOE, without realized derivatives

   $ 74.84       $ 62.33       $ (12.51)         (17)

Average price per BOE, with realized derivatives

   $ 74.67       $ 60.85       $ (13.82)         (19)

Production:

           

Oil (MBbls)

     94         356         262         278

Natural gas and natural gas liquid (MMcf)

     304         1,493         1,189         391

Total (MBoe)(2)

     145         604         459         317

Average daily production volume:

           

Oil (Bbls/d)

     258         972         714         277

Natural gas and natural gas liquids (Mcf/d)

     832         4,079         3,247         390

Total (Boe/d)

     397         1,652         1,255         316

 

(1) Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains or losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period.
(2) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

 

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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.

 

     Year Ended
December 31,
 
     2011     2012  

Average realized oil price ($/Bbl)

   $ 92.43      $ 85.60   

Average NYMEX ($/Bbl)

   $ 94.80      $ 93.73   

Differential to NYMEX

   $ (2.37   $ (8.13

Average realized oil price to NYMEX percentage

     98     91

Average realized natural gas price ($/Mcf)

   $ 7.02      $ 4.85   

Average NYMEX ($/Mcf)

     3.92      $ 2.91   

Differential to NYMEX

   $ 3.10      $ 1.94   

Average realized natural gas price to NYMEX percentage

     179     167

Oil revenues increased 250% from $8.7 million in 2011 to $30.4 million in 2012 as a result of an increase in oil production volumes of 262 MBbls offset by a decrease in average oil prices of $6.83 per barrel. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $24.2 million while decreases in oil prices accounted for a negative change of $2.5 million.

Natural gas and natural gas liquid revenues increased 239% from $2.1 million in 2011 to $7.2 million in 2012. The revenue increase is primarily a result of an increase in natural gas production volumes of 1,189 MMcf offset by a decrease in average natural gas prices of $2.17 per Mcf. Of the overall change in natural gas sales, increases in production volumes accounted for a positive change of $8.3 million while decreases in natural gas prices accounted for a negative change of $3.2 million. Natural gas revenue includes revenue from the sale of NGLs volumes.

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

 

     Year Ended
December 31,
              
     2011      2012      Change     % Change  

Operating expenses (in thousands, except percentages):

          

Lease operating expenses

   $ 1,446       $ 4,646       $ 3,200        221

Production and ad valorem taxes

     610         2,412         1,802        295

Depreciation, depletion and amortization

     1,247         6,406         5,159        414

General and administrative expenses

     1,357         3,629         2,272        167

Accretion of asset retirement obligations

     32         66         34        106
  

 

 

    

 

 

    

 

 

   

Total operating expenses

   $ 4,692       $ 17,159       $ 12,467        266
  

 

 

    

 

 

    

 

 

   

Expense per Boe:

          

Lease operating expenses

   $ 9.99       $ 7.69       $ (2.30     (23 )% 

Production and ad valorem taxes

     4.21         3.99         (0.22     (5 )% 

Depreciation, depletion and amortization

     8.61         10.60         1.99        23

General and administrative expenses

     9.37         6.00         (3.37     (36 )% 

Accretion of asset retirement obligations

     0.22         0.11         (0.11     (50 )% 
  

 

 

    

 

 

    

 

 

   

Total operating expenses per Boe

   $ 32.40       $ 28.39       $ (4.01     (12 )% 
  

 

 

    

 

 

    

 

 

   

 

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Lease Operating Expenses. Lease operating expenses increased 221% from $1.4 million in 2011 to $4.6 million in 2012 primarily due to the increase in operated well count from 2011 to 2012, increases in costs for repair and maintenance for 89 new wells added, additional lease operators and increased water disposal activity. On a per Boe basis, lease operating expenses decreased from $9.99 per Boe to $7.69 per Boe.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 295%, or $1.8 million from $0.6 million in 2011 to $2.4 million in 2012 due to increased wellhead revenue resulting from higher production from our increase in the number of wells brought on production.

Depreciation, Depletion and Amortization. DD&A expense increased by $5.2 million from $1.2 million in 2011 to $6.4 million in 2012 due to an increase in capitalized costs and production volumes.

General and Administrative Expenses. General and administrative expenses increased $2.2 million from $1.4 million in 2011 to $3.6 million in 2012 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.

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

 

     Year Ended
December 31,
             
     2011     2012     Change     % Change  

Other income (expense) (in thousands, except percentages):

        

Interest expense, net

   $ (458   $ (6,285   $ (5,827     1,272

Income from equity investment

     136        267        131        96

Prepayment premium on extinguishment of debt

     —          (6,597     (6,597  

Derivative loss

     (255     (2,190     (1,935     759

Other income (expense)

     (267     (81     186        (70 )% 
  

 

 

   

 

 

   

 

 

   

Total other income (expense), net

   $ (844   $ (14,886   $ (14,042     1,664
  

 

 

   

 

 

   

 

 

   

Interest Expense. Interest expense increased $5.8 million from $0.5 million in 2011 to $6.3 million in 2012 primarily due to having a full year with the mezzanine debt facility outstanding during 2012 in addition to higher weighted-average outstanding borrowings under our credit agreement.

Income from Equity Investment. Earnings in our 50% owned subsidiary SPS increased from $0.1 million in 2011 to $0.3 million in 2012 due to increased revenue from SPS’ expansion of its frac tank rental operations during 2012.

Prepayment Premium on Extinguishment of Debt. In 2012, we incurred a $6.6 million cash charge related to a call premium on our then outstanding debt facility. In 2011, there were no such prepayment charges related to debt extinguishment.

Derivative Loss. Loss on derivative instruments grew $1.9 million from $0.3 million in 2011 to $2.2 million in 2012 primarily as a result of the impact of changing commodity prices on increased hedging activities.

Gain on Sales of Oil and Natural Gas Properties

During the year ended December 31, 2012, we entered into several transactions whereby we sold a total of 3,612 unevaluated net acres for total proceeds of $9.3 million and a total realized gain of $7.8 million. This compares to our activity during the year ended December 31, 2011 where we entered into several transactions, selling a total of 10,264 unevaluated net acres for total proceeds of $10.3 million and a total realized gain of $6.6 million.

 

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Income Tax Expense

During the year ended December 31, 2012, we recognized $0.6 million of expense associated with our Texas margin tax obligation, an increase of $0.4 million, or 377.6%, as compared to the $0.1 million we recognized during the year ended December 31, 2011. This increase was attributable to our net increase in operating income, the components of which are discussed above.

Liquidity and Capital Resources

We expect that our primary sources of liquidity and capital resources after the consummation of this offering will be cash flows generated by operating activities and borrowings under our revolving credit facility. Depending upon market conditions and other factors, we may also have the ability to issue additional equity and debt if needed. We intend to use the net proceeds from this offering to make a cash payment in settlement of the Preferred Return, to reduce amounts drawn under our revolving credit facility and any remaining net proceeds will be used to fund a portion of our exploration and development program.

Historically, our predecessor’s primary sources of liquidity have been cash flows from operations, borrowings under Parsley LLC’s credit facilities and equity provided by investors, including our management team and NGP. To date, our predecessor’s primary use of capital has been for the development and exploration of oil and natural gas properties and increasing our acreage position. Our predecessor’s borrowings were approximately $430.2 million and $119.7 million at December 31, 2013 and 2012, respectively. 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. On February 5, 2014, Parsley LLC and Parsley Finance Corp. issued $400 million of 7.5% senior unsecured notes due February 15, 2022. 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 our subsidiaries, other than Parsley LLC and Parsley Finance Corp. The issuance of these notes resulted in net proceeds, after discounts and offering expenses, of approximately $391 million, $198.5 million of which was used to repay all outstanding borrowings, accrued interest and a prepayment penalty under our 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 our revolving credit facility. See “—Senior unsecured notes” below. As of April 1, 2014, we had $130.3 million outstanding under our revolving credit facility. See “—Revolving Credit Facility” below.

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 approximately 40% to 60% of our projected oil production over a two-to-three year period at a given point in time, although we may from time to time hedge more or less than this approximate range.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or fund a portion of our capital expenditures using borrowings under our credit facilities, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our credit facilities. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

 

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Cash Flows

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

 

     Predecessor  
     Year Ended
December 31,
 
     2011      2012      2013  
     (in thousands)  

Net cash provided by operating activities

   $ 16,031       $ 5,025         53,235   

Net cash used in investing activities

     (15,654)         (89,539)         (425,611)   

Net cash provided by financing activities

     19,729         74,245         378,096   

Net cash provided by operating activities was approximately $16.0 million, $5.0 million and $53.2 million for the years ended December 31, 2011, 2012 and 2013, respectively. Revenues, net of operating expenses, increased for the year ended December 31, 2013 as compared to the year ended December 31, 2012, and therefore our net cash provided by operating activities were consistent during that same period. 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.

Net cash used in investing activities was approximately $15.6 million, $89.5 million and $425.6 million for the years ended December 31, 2011, 2012 and 2013, respectively. The increased amount of cash used in investing activities in the year ended December 31, 2013 as compared to the year ended December 31, 2012 and in the year ended December 31, 2012 as compared to the year ended December 31, 2011 was due to additional rigs operating during 2013 over 2012 and 2012 over 2011, in addition to drilling higher working interest wells in 2013 over 2012 and acquisition activity.

Net cash provided by financing activities was approximately $19.7 million, $74.2 million and $378.1 million for the years ended December 31, 2011, 2012 and 2013, respectively. For 2013, the cash provided by financing activities was primarily related to new borrowings under our credit facilities in addition to the $73.5 million equity investment that was closed in June 2013. For 2011 and 2012, the cash provided by financing activities consisted primarily of net borrowings under long-term debt.

Working Capital

Our working capital totaled ($54.2) million and ($10.0) million at December 31, 2013 and 2012, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $19.4 million and $13.7 million at December 31, 2013 and 2012, respectively. 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 after application of the estimated net proceeds from this offering, as described under “Use of Proceeds,” 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.

Revolving Credit Facility

On October 21, 2013, we entered into an amended and restated first lien revolving credit facility with Wells Fargo Bank, National Association, as administrative agent (“Administrative Agent”), and a syndicate of lenders with a maximum revolving credit facility of $750 million and a sublimit for letters of credit of $2.5 million.

 

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

 

   

incur additional indebtedness;

 

   

sell assets;

 

   

make loans to others;

 

   

make investments;

 

   

enter into mergers;

 

   

make or declare dividends;

 

   

hedge future production or interest rates;

 

   

incur liens; and

 

   

engage in certain other transactions without the prior consent of the lenders.

The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semi-annually each March and September, with such redetermination effective each April and October, respectively, and depends on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the Administrative Agent. As of December 31, 2013, our borrowing base was $280.0 million, and we had $234.8 million outstanding under our revolving credit facility. In connection with the issuance of our senior unsecured notes, our borrowing base was reduced to $227.5 million. In connection with our April 2014 borrowing base redetermination, we have received approval from the lenders under the credit facility for a borrowing base of $365.0 million. As of April 1, 2014, we had $130.3 million outstanding under our revolving credit facility. The revolving credit facility matures on September 10, 2018.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for alternate base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing 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. As of December 31, 2013, borrowings and letters of credit outstanding under our revolving credit facility had a weighted average interest rate of 3.31%. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

Our first lien revolving credit facility also requires us to maintain the following financial ratios:

 

   

a current ratio, which is the ratio of our consolidated current assets (includes unused commitments under the first lien revolving credit facility and unrestricted cash and excludes certain derivative assets) to our consolidated current liabilities (excludes obligations under the first lien revolving credit facility and certain derivative liabilities), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and

 

   

a minimum interest coverage ratio, which is the ratio of EBITDAX (as defined in our first lien revolving credit facility) to consolidated interest expense, of not less than 2.5 to 1.0 as of the last day of any fiscal

 

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quarter for the four fiscal quarters ending on such date; provided that for the fiscal quarters ending September 30, 2013, December 31, 2013 and March 31, 2014, EBITDAX and consolidated interest expense for the relevant period shall be deemed to equal EBITDAX or consolidated interest expense, as applicable, for the three, six or nine-month period then ending, as applicable, multiplied by 4, 2 and 4/3, respectively.

In April 2014, we determined that as of December 31, 2013, we were not in compliance with the quarterly current ratio requirement under our credit facility and that as a result an event of default had occurred under this facility. On April 11, 2014, we received a waiver for this event of default from the required lenders and are currently in compliance with the current ratio requirement.

Senior unsecured notes

On February 5, 2014, Parsley LLC and Parsley Finance Corp. issued $400 million of 7.5% senior unsecured notes (the “Notes”) due February 15, 2022. Interest is payable on the Notes semi-annually in arrears on each February 15 and August 15, commencing August 15, 2014. The Notes are guaranteed on a senior unsecured basis by our subsidiaries other than Parsley LLC and Parsley Finance Corp. The issuance of these notes resulted in net proceeds, after discounts and offering expenses, of approximately $391 million, $198.5 million of which was used to repay all outstanding borrowings, accrued interest and a prepayment penalty under our 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 our revolving credit facility.

At any time prior to February 15, 2017, we 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, we 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, we 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 decline subsequently to below investment grade, the suspended covenants will be reinstated.

Capital Requirements and Sources of Liquidity

Our 2014 capital budget for drilling and completion is approximately $430.0 million for an estimated 151 gross (129 net) vertical wells and 30 gross (23 net) horizontal wells. Our capital budget excludes acquisitions. Substantially all of our capital budget will be spent in the Midland Basin. During the year ended December 31, 2013, our aggregate drilling and completion capital expenditures were $268.4 million, excluding acquisitions.

However, the amount and timing of these 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

 

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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. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. See “Business – Developed and Undeveloped Acreage.” In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

Historically, our predecessor’s primary sources of liquidity have been cash flows from operations, borrowings under Parsley LLC’s credit facilities and equity provided by investors, including our management team and NGP. To date, our predecessor’s primary use of capital has been for the development and exploration of oil and natural gas properties and increasing our acreage position. Our future successes in growing proved reserves and production will be highly dependent on the capital resources available to us. As we pursue reserve and production growth, we monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Based upon current oil and natural gas price expectations for 2014, following the closing of this offering and the consummation of the transactions described under “Corporate Reorganization,” we believe that our cash flow from operations, proceeds of this offering and borrowings under our revolving credit facility will be sufficient to fund our operations through 2014. 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. We cannot assure you that operations and other needed capital will be available on acceptable terms or at all. Further, our capital expenditure budget for 2014 does not allocate any amounts for leasehold interest and additions to our 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.

 

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Contractual Obligations

A summary of our predecessor’s contractual obligations as of December 31, 2013 is provided in the following table.

 

     Predecessor  
     Payments Due by Period
For the Year Ended December 31,
 
       2014        2015      2016      2017      2018     Thereafter      Total  
     (in thousands)  

Revolving Credit Facility(1)(4)

   $ —         $ —         $ 234,750       $ —           —        $ —         $ 234,750   

Second Lien Credit Facility(2)(4)

     —           —           192,854         —           —          —           192,854   

Aircraft Term Loan

     227         238         250         263         1,615        —           2,593   

Office and equipment leases

     757         738         679         699         715        1,353         4,941   

Asset retirement obligations(3)

     —           836         712         92         102        6,535         8,277   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $   984       $ 1,812       $ 429,245       $ 1,054       $ 2,432      $ 7,888       $ 443,415   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on Parsley’s first lien revolving credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. At December 31, 2013, the maturity date of our revolving credit facility was the earlier of September 10, 2018 or the date that was 91 days prior to the stated maturity of our second lien credit facility, December 31, 2016. The second lien credit facility was repaid in full and terminated in February 2014.
(2) This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on Parsley’s second lien credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.
(3) Amounts represent estimates of our predecessor’s future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.
(4) On February 5, 2014, Parsley LLC and Parsley Finance Corp. issued $400 million of 7.5% senior unsecured notes due February 15, 2022. We repaid all outstanding borrowings under our second lien credit facility and $174.8 million of principal amounts outstanding under our revolving credit facility with the net proceeds from these notes.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates 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 and interest rates. 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.

 

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To reduce the impact of fluctuations in oil prices on our revenues, our predecessor periodically enters into commodity derivative contracts with respect to certain of our oil production through various transactions that limit the downside of future prices received. We seek to hedge approximately 40% to 60% of our expected oil production on a rolling 24 to 36 month basis. 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. In addition, as a result of the recent increase in natural gas prices, we have hedged 2,000,000 MMBtus and 3,600,0000 MMBtus of our expected 2014 and 2015 natural gas production, respectively. See “—Overview—Realized Prices on the Sale of Oil, Natural Gas and NGLs.”

Counterparty and Customer Credit Risk

Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While our predecessor does not require our counterparties to our derivative contracts to post collateral, our predecessor does 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 predecessor’s derivative contracts currently in place are lenders under Parsley LLC’s credit facilities, with investment grade ratings.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of its oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high. In addition, Parsley maintains the ability to net revenue payments to joint interest owners for those not paying their joint interest billings.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rate Risk

At December 31, 2013, we had $427.6 million of variable-rate debt outstanding, with a weighted average interest rate of LIBOR plus 7.16%, or 7.70%, including incorporation of the second lien LIBOR floor of 1.00%. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $4.3 million per year. We may begin entering into interest rate swap arrangements on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR. See “—Liquidity and Capital Resources—Our Credit Facilities.”

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated 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

 

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of our consolidated financial statements. See Note 3 of the notes to the audited consolidated financial statements included elsewhere in this prospectus 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 Consolidated Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

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.

 

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Asset Retirement Obligations

We have significant obligations to remove tangible equipment and facilities associated with our oil and 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.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended 2013, 2012 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

Currently, neither we nor our predecessor have off-balance sheet arrangements.

 

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BUSINESS

Our Company

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. The Permian Basin is located in West Texas and Southeastern New Mexico and is comprised of three primary sub-areas: the Midland Basin, the Central Basin Platform and the Delaware Basin. These areas are characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons, extensive production histories, long-lived reserves and historically high drilling success rates. Our properties are primarily 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 intend to supplement our vertical development drilling activity with horizontal wells targeting various stacked pay intervals in the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline) and Atoka shales.

We began operations in August 2008 when we acquired the operator rights to wells producing from the Spraberry Trend in the Midland Basin from Joe Parsley, a co-founder of Parker and Parsley. As of December 31, 2013, we continue to operate 98 gross (2.5 net) of these wells. Excluding those legacy 98 gross wells, as of December 31, 2013 we had an average working interest of 57% in 431 gross producing wells. In total, we have interests in 530 gross (247 net) producing wells, all of which are in the Midland Basin and 99% of which we operate. Since our inception, we have leased or acquired 98,656 net acres in the Permian Basin, approximately 76,356 of which is in the Midland Basin. Since we commenced our drilling program in November 2009, we have operated up to 10 rigs simultaneously and averaged nine operated rigs for the 12 months ended December 31, 2013. Driven by our large-scale drilling program in the core of the Midland Basin, we have grown our net average daily production to 11,139 Boe/d for the month ended March 31, 2013, substantially all of which is organic growth from wells we have drilled. We are currently operating nine vertical drilling rigs and one horizontal drilling rig and expect to operate seven to eight vertical rigs and increase to five horizontal rigs by the first quarter of 2015.

We intend to grow our reserves and production through the development, exploitation and drilling of our multi-year inventory of identified potential drilling locations. As of December 31, 2013, we have identified 1,362 80- and 40-acre potential vertical drilling locations, 1,694 20-acre potential vertical drilling locations and 1,315 potential horizontal drilling locations on our existing acreage, excluding our Gaines County (Midland Basin) and Southern Delaware Basin acreage. As we expand our drilling program to our undeveloped Midland Basin acreage in Gaines County (Midland Basin) and our Southern Delaware Basin acreage, we expect to identify additional vertical and horizontal drilling locations. 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. Additionally, we commenced our vertical appraisal drilling program in the Delaware Basin during the first quarter of 2014 and expect to drill three vertical appraisal wells in 2014. We believe our acreage in the Delaware Basin may also benefit from the application of horizontal drilling and completion techniques. We expect to supplement organic growth from our drilling program by proactively leasing additional acreage and selectively pursuing acquisitions that meet our strategic and financial objectives, with an emphasis on oil-weighted reserves in the Midland Basin.

Our 2014 capital budget for drilling and completion is approximately $430.0 million for an estimated 151 gross (129 net) vertical wells and 30 gross (23 net) horizontal wells. Our capital budget excludes acquisitions. We anticipate that substantially all of our 2014 capital budget will be directed toward the Midland Basin. During the year ended December 31, 2013, our aggregate drilling and completion capital expenditures were $268.4 million, excluding acquisitions. We expect the average working interest in wells we drill during 2014 will be approximately 75% to 85%.

The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including

 

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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.

We measure the expected return of our wells based on EUR and the related costs of acquisition, development and production. Based on estimates prepared by NSAI, as of December 31, 2013, our proved undeveloped vertical locations in our Midland Basin-Core and Midland Basin-Tier I areas have average EURs of 214.8 MBoe (109.1 MBbls of oil, 300.5 MMcf of natural gas and 55.6 MBbls of NGLs) and 109.3 MBoe (69.0 MBbls of oil, 114.5 MMcf of natural gas and 21.2 MBbls of NGLs), respectively. These estimates assume average 30-day initial production rates of 149.7 Boe/d (76.0 Bbls/d of oil, 209.3 Mcf/d of natural gas and 38.8 Bbls/d of NGLs), and 84.5 Boe/d (53.3 Bbls/d of oil, 88.5 Mcf/d of natural gas and 16.4 Bbls/d of NGLs), respectively, which is consistent with the performance of our existing producing wells in these areas. We have no proved undeveloped locations on our Midland Basin-Other or Southern Delaware Basin properties. To date, the average drilling and completion cost for the 201 and 125 vertical development wells we have drilled and placed on production in our Midland Basin-Core and Midland Basin-Tier I areas, respectively, is approximately $2.3 million and approximately $2.0 million, respectively. The average 2-stream 30-day initial production rate for all of the wells we drilled during the third and fourth quarters of 2013 was 153 Boe/d (comprised of 90 Bbls/d of oil and 373 Mcf/d of natural gas, which includes NGLs). Please see “Prospectus Summary—Recent Developments—Recent Well Results.”

The following table summarizes our acreage and technically identified drilling locations in the Permian Basin as of December 31, 2013:

 

     Net Acreage      Identified Drilling Locations(1)      Vertical
Drilling
Inventory

(Years(5))
     Horizontal
Drilling
Inventory

(Years(6))
 
        Vertical(2)      Horizontal(4)        

Area(3)

      80-and 40-acre      20-acre           

Midland Basin-Core

     28,555         824         1,142    &nb